Enhanced carbon dioxide-based geothermal energy generation systems and methods

ABSTRACT

A system comprises an injection well for accessing reservoir at a first temperature; a production well in fluid communication with the reservoir; a working-fluid supply system providing a non-water based working fluid to the injection well at a second temperature lower than the first temperature, wherein exposure of the working fluid to the first temperature heats the working fluid to a third temperature and at least a portion of the working fluid at the third temperature is produced as a production fluid; and an energy recovery system that converts energy contained in the production fluid to electricity or heat, wherein the energy recovery system includes a waste heat recovery apparatus that recovers waste heat and uses it to heat the production fluid to a fourth temperature that is higher than the third temperature, wherein the waste heat is recovered from equipment of or a process stream.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of and claims the benefit of priorityto U.S. application Ser. No. 15/835,276, filed Dec. 7, 2017, which is acontinuation of and claims the benefit of priority to U.S. applicationSer. No. 13/800,720, filed Mar. 13, 2013, issued as U.S. Pat. No.9,869,167 on Jan. 16, 2018, which claims the benefit of priority to U.S.Provisional Patent Application Ser. No. 61/725,270, entitled “ENHANCEDCARBON-DIOXIDE BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS,”filed Nov. 12, 2012, which applications are incorporated by referenceherein in their entirety.

BACKGROUND

In light of global climate change and in response to an increased desireto reduce dependence on foreign oil supplies, renewable energy systems,such as wind, solar and geothermal-based systems are being increasinglyresearched and developed. However, many such systems have only limitedpotential due to, for example, high costs, overall processinefficiencies, possible adverse environmental impact, and the like.

SUMMARY

This disclosure describes systems and methods for efficiently recoveringgeothermal heat from reservoirs by injecting a non-water based workingfluid, such as carbon dioxide (CO₂), into the reservoir to extractgeothermal heat. The CO₂ can then be produced back to the surface and aportion of the geothermal energy captured by the CO₂ can be recovered byan energy recovery apparatus, such as an electricity productionapparatus (e.g., an expansion device driving a generator) or a heatrecovery apparatus (e.g., one or more heat exchangers for heating asecond working fluid).

In particular, this disclosure describes recovering geothermal heat fromreservoirs that include a native fluid including a solution comprisingnatural gas, and in particular methane (CH₄). The CO₂ can cause the CH₄to come out of solution with the native fluid such that the CH₄ forms aproduction fluid with the CO₂. The production fluid can be heated bygeothermal heat and produced to the surface where at least a portion ofthe CH₄ can be separated from the production fluid and combusted toincrease the overall temperature of the production fluid before it isfed into the energy recovery apparatus. Such a system and method canutilize the chemical properties of CO₂ to extract CH₄ from thereservoir, and then can use the chemical energy stored in a portion ofthe CH₄ to supplement the geothermal energy captured by the productionfluid. The recovery of methane from the reservoir and subsequentcombustion of a portion of the methane to boost production fluidtemperature or pressure, or both, can increase the overall systemefficiency and the overall power produced compared to geothermal capturealone. The methane capture and use of the systems and methods of thepresent disclosure can allow for economically viable recovery ofgeothermal energy from low-temperature reservoirs (e.g., down to about15° C., or, in some situations, down to about 10° C.). The systems andmethods of the present invention can, therefore, open up reservoirs forgeothermal exploitation that heretofore had been economically difficultor impossible to achieve.

The present disclosure describes a system comprising one or moreinjection wells for accessing one or more underground reservoirs, theone or more reservoirs being at one or more first temperatures andcontaining at least one native fluid, the native fluid including asolution comprising methane, each of the one or more injection wellshaving an injection well reservoir opening in fluid communication withat least one of the one or more reservoirs. The system further includesone or more production wells, each having a production well reservoiropening in fluid communication with at least one of the one or morereservoirs. A working-fluid supply system provides a non-water basedworking fluid to the one or more injection wells at a second temperaturelower than the first temperatures. Exposure of the non-water basedworking fluid to the native fluid causes at least a portion of themethane to come out of solution with the native fluid to form aproduction fluid of at least a portion of the non-water based workingfluid and the portion of the methane. Exposure of the mixture to thefirst temperatures heats the production fluid to a third temperaturethat is higher than the second temperature, wherein the production fluidis capable of entering one or more of the production well reservoiropenings. The system also includes an energy recovery apparatus in fluidcommunication with the one or more productions wells, wherein energycontained in the production fluid can be converted to electricity, heat,or a combination thereof, in the energy recovery apparatus.

The present disclosure also describes a method comprising introducing anon-water based working fluid at a first temperature through one or moreinjection wells to one or more underground reservoirs containing atleast one native fluid, the native fluid including a solution comprisingmethane, wherein the one or more reservoirs are at one or more secondtemperatures that are greater than the first temperature, exposing thenon-water based working fluid to the native fluid so that at least aportion of the methane comes out of solution with the native fluid toform a production fluid of at least a portion of the non-water basedworking fluid and the portion of the methane, exposing the productionfluid to the second temperature to heat the production fluid to a thirdtemperature that is greater than the first temperature, producing theproduction fluid through one or more production wells, and extractingenergy from the production fluid.

These and other examples and features of the present systems and methodswill be set forth in part in the following Detailed Description. ThisSummary is intended to provide an overview of the present subjectmatter, and is not intended to provide an exclusive or exhaustiveexplanation. The Detailed Description below is included to providefurther information about the present systems and methods.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified schematic diagram of an example geothermal energyrecovery system.

FIG. 2 is a simplified schematic diagram of another example geothermalenergy recovery system.

FIG. 3 is a simplified schematic diagram of another example geothermalenergy recovery system.

FIG. 4 is a simplified schematic diagram of another example geothermalenergy recovery system.

FIG. 5 is a simplified schematic diagram of the formation of a highmethane concentration zone within a reservoir.

FIG. 6 is a simplified schematic diagram of the placement of variousinjection wells and production wells for extraction of working fluid andmethane from a reservoir.

FIG. 7A is a phase diagram of an example power cycle for a CO₂-onlyworking fluid.

FIG. 7B is a phase diagram of an example power cycle for a CO₂-methaneworking fluid.

FIG. 8 is a simplified schematic diagram of another example geothermalenergy recovery system.

FIG. 9 is a simplified schematic diagram of another example geothermalenergy recovery system.

FIG. 10 is a simplified schematic diagram of another example geothermalenergy recovery system.

FIG. 1A shows a graph of electricity produced by a methane-enhancedgeothermal energy recovery system compared to a non-enhanced CO₂-basedgeothermal energy recovery system and compared to methane combustiondepending on the wellhead temperature of the produced fluid.

FIG. 11B shows a graph of electricity produced by a methane-enhancedgeothermal energy recovery system compared to a non-enhanced CO₂-basedgeothermal energy recovery system and compared to methane combustiondepending on the bottomhole temperature of the produced fluid.

FIG. 12A shows a graph of electricity produced by a methane-enhancedgeothermal energy recovery system compared to a non-enhanced CO₂-basedgeothermal energy recovery system and compared to methane combustiondepending on the wellhead temperature of the produced fluid.

FIG. 12B shows a graph of electricity produced by a methane-enhancedgeothermal energy recovery system compared to a non-enhanced CO₂-basedgeothermal energy recovery system and compared to methane combustiondepending on the bottomhole temperature of the produced fluid.

FIG. 13 shows a graph of electricity produced by a waste heat-enhancedgeothermal energy recovery system compared to a non-waste heat enhancedCO₂-based geothermal energy recovery system and compared to waste heatrecovery alone.

FIG. 14 shows a graph of the available energy values from varioussources.

FIG. 15 shows a graph of the electricity produced from various sources.

DETAILED DESCRIPTION

In the following detailed description, reference is made to theaccompanying drawings that form a part hereof, and in which is shown byway of illustration, specific examples in which the invention may bepracticed. These examples are described in sufficient detail to enablethose skilled in the art to practice the invention, and it is to beunderstood that other embodiments may be utilized. It is also to beunderstood that structural, procedural, chemical and system changes canbe made without departing from the spirit and scope of the presentinvention. The following detailed description is, therefore, not to betaken in a limiting sense, and the scope of the present invention isdefined by the appended claims and their equivalents.

The present disclosure describes geothermal energy recovery systems andmethods using a non-water based working fluid, such as carbon dioxide(CO₂) for the recovery of geothermal energy. The geothermal energyrecovery systems and methods can include aspects of the example systemsand methods disclosed in U.S. Published Application No. US2012-0001429to Saar, et al., entitled “CARBON DIOXIDE-BASED GEOTHERMAL ENERGYGENERATION SYSTEMS AND METHODS RELATED THERETO.” and U.S. patentapplication Ser. No. 13/554,868 to Saar et al., entitled “CARBONDIOXIDE-BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS RELATEDTHERETO,” filed on Jul. 20, 2012, both of which are hereby incorporatedby reference herein in their entireties. As described in theseapplications, a carbon dioxide working fluid can travel through thereservoir as a gas plume such that the system in the applications arereferred to as Carbon Dioxide (or CO₂) Plume Geothermal (“CPG”) systems.

The present disclosure also describes feeding the non-water basedworking fluid to a reservoir that contains a native fluid comprising asolution including methane. For example, the reservoir can comprise adeep brine aquifer comprising a brine solution with natural gas (thenatural gas comprising generally about 97% methane or more) dissolved inthe brine solution. Because “natural gas,” as it is used herein, isgenerally at least about 97 wt % methane or more, the remainder of thisdisclosure will refer to it as “methane” for the sake of brevity. Itwill be understood by a person of ordinary skill in the art that“methane” can refer to other gaseous hydrocarbons that can be includedin natural gas, such as ethane, propane, and higher order alkanes. Theinjection of a carbon dioxide working fluid into the brine aquifer cancause a portion of the CO₂ to dissolve into the brine solution, whichcan force a substantial portion of the dissolved methane out ofsolution. The released methane can combine with the remaining CO₂ toform a production fluid in the form of a gaseous plume similar to theCO₂ plumes in the CPG systems. In addition, a zone of a mixture of brinesolution with dissolved or free-phase methane plus CO₂ can form betweenthe native brine solution and the zone of CO₂ combined with methane. Thefluid comprising brine, methane, and/or CO₂ can also form a productionfluid, in addition to the production fluid that is similar to a CO₂plume formed in a CPG system. As described in more detail below, aportion of the methane recovered from the brine aquifer can be combustedto increase the temperature or the pressure, or both, of the productionfluid prior to recovering energy from the production fluid, such as bypassing the production fluid through an expansion device that powers agenerator to produce electricity. The remainder of the methane presentin the production fluid can either be separated out and sold, or it canbe re-injected into the reservoir to provide for further production anduse in the energy recover system. The use of recovered methane to boostthe economic efficiency of the system can be referred to herein asmethane-enhanced CO₂ Plume Geothermal (“ME-CPG”) systems.

Alternatively, the reservoir can include an oil or natural gas fieldwhere the oil or natural gas hydrocarbons have been partially recoveredusing conventional recovery methods. The oil or natural gas hydrocarbonscan be recovered via the injection of carbon dioxide or other recoveryfluids into the field in order to release a portion of the hydrocarbonsfrom the reservoir. This process can be referred to as “enhanced oilrecovery” (EOR) (described in more detail below). The production fluidfrom an EOR field can include the CO₂ working fluid, methane and othernatural gas components, other higher order hydrocarbons, and brine. Aswith the brine aquifer reservoir described above, a portion of themethane recovered from the EOR field can be used to increase thetemperature, the pressure, or both of the production fluid beforefurther energy recovery is conducted. The EOR hydrocarbons can beseparated from the production fluid and sold. A portion of the separatedhydrocarbons can also be combusted to heat the working fluid or increasethe working fluid's pressure prior to energy recovery.

The systems of this disclosure can include components or aspects whereconsiderable heat is generated-heat that typically is lost to theatmosphere. For example, both EOR and CPG systems can include one ormore compressors for the CO₂ so that the CO₂ can be injected back intothe reservoir for further oil or natural gas recovery, geothermal heatrecovery, or CO₂ sequestration. The compressors can generateconsiderable heat, on the order of 400 to 450 kilojoules (U) perkilogram (kg) of CO₂ compressed for each stage of compression, dependingon the type of compressor system used. EOR systems can also generateconsiderable heat during the separation of the oil and natural gashydrocarbons from the production fluid, for example if a portion of themethane or other produced fluid is combusted to heat the productionfluid in order to improve separation efficiency.

In some examples, the geothermal energy recovery system and the EORsystem (if present) can be co-located with another facility type, e.g.,a power plant or an ethanol or biofuel production facility. For example,the co-located facility can be the initial source of CO₂ that iscompressed and injected into the reservoir for the recovery ofgeothermal heat, methane, and/or other hydrocarbons. The co-locatedfacility can also typically produce considerable waste heat. Inaddition, for a co-located biofuel production facility, such as anethanol plant, a portion of the biofuel produced at the plant can becombusted to increase the temperature of a working fluid or productionfluid or to increase the pressure of the working fluid, or both, priorto energy recovery from the working fluid or production fluid.Similarly, biofuel or other from an off-site third party can be obtainedand transported to the geothermal recovery system and combusted toincrease the temperature of a working fluid or production fluid or toincrease the pressure of the working fluid, or both.

In some examples, the systems and methods of the present disclosure caninclude a heat recovery system for recovering waste heat generated bysome other aspect of the system or method, such as waste heat from theCO₂ compressors, the EOR separation system, or a co-located facility.The waste heat recovered by the heat recovery system can also be used toincrease the temperature, the pressure, or both of the production fluidbefore it is fed into the energy recovery system (e.g., the expansiondevice and generator). Waste heat capture with a heat recovery systemcan increase the efficiency of the geothermal energy recovery system andmethod similar to the enhancement provided by recovered methanecombustion in the ME-CPG system. The capture of waste heat to boost theeconomic efficiency of the system can be referred to herein as wasteheat-enhanced CO₂ Plume Geothermal (“WHE-CPG”) systems. It will beappreciated that both ME-CPG and WHE-CPG can be used in the same system.

Conventional Geothermal Energy Technology

Geothermal energy is heat energy generated and stored within the earth(or any other planet), which can be “mined” for various uses, includingto produce electricity, for direct use, or for ground-source heat pumps.Geothermal energy sources can be relatively constant with heat energyreplenished on human time scales after being “mined.” Geothermal energyalso can require no storage other than the earth.

Potential uses of conventional geothermal energy are generallytemperature dependent, with cascading systems utilizing a singlegeothermal resource for multiple purposes. Water-based geothermalsystems that use water as a working fluid (e.g., conventionalwater-based enhanced geothermal systems (EGS) and conventional non-EGSwater-based) can require very high temperatures. For example,electricity generation at water-based geothermal power plants typicallyrequires temperatures in excess of 165° C. Direct uses, such asaquaculture, greenhouse, industrial and agricultural processes, resorts,space and district heating (wells to structures) from such systems canutilize more moderate temperatures of about 38 to 165° C. when water isthe subsurface geothermal working fluid. Residential and commercialbuilding ground-source heat pumps from water-based geothermal systems,which may use a secondary heat exchange fluid (e.g., isobutene) in orderto transfer geothermal heat energy from the ground for use, cangenerally require temperatures between about 4 and 38° C.

Definitions

The terms “subterranean” or “subsurface” or “underground,” as usedherein, can refer to locations and/or geological formations beneath theEarth's surface.

The term “in silu,” as used herein, can refer to a natural or originalposition or place of a geologic feature which may be above ground orunderground, such that it is located in a place where it was originallyformed or deposited by nature and has remained substantially undisturbedover time, such that it is in substantially the same original condition.A geologic feature can be rock, mineral, sediment, reservoir, caprockand the like, or any combination thereof. A geologic feature is furtherconsidered to remain “in situ” following minor manmade disturbances usedto create and/or position components, such as channels such as injectionwells and/or production wells, within, around or near the feature. Afeature is also considered to remain “in situ” following minorman-initiated disturbances, such as causing a controllable or limitedamount of rock, mineral, sediment or soil to become dislodged as aresult of the minor manmade or natural disturbance. In contrast, afeature is not considered to remain “in situ” following any type oflarge-scale manmade disturbances, including large-scale hydrofracturing(such as to create an artificial reservoir), or man-initiateddisturbances, such as permanent deformation of a geologic feature,earthquakes and/or tremors following large-scale hydrofracturing, all ofwhich can have a further negative impacts on groundwater flow paths,habitats and man-made structures.

The term “large-scale hydrofracturing,” as used herein, can refer to aknown method for creating or inducing artificial fractures and/or faultsin a feature, such as a rock or partially consolidated sediments,typically during operation of an enhanced geothermal system (EGS). See,for example, U.S. Pat. No. 3,786,858 to Potter, which employs water forhydraulic fracturing of rock to create a thermal geological reservoirfrom which fluid is transported to the surface. Large-scalehydrofracturing is known to create unintended fluid flow pathways thatcan result in fluid loss or “shortcutting,” which in turn decreasesgeothermal heating efficiencies of the working fluid. Large-scalehydrofracturing can also cause (micro-) seismicity and damages tonatural and/or manmade structures.

The term “rock,” as used herein, can refer to a relatively hard,naturally formed mineral, collection of minerals, or petrified matter. Acollection of rocks is commonly referred to as a “rock formation.”Various types of rocks have been identified on Earth, to include, forexample, igneous, metamorphic, sedimentary, and the like. A rock canerode or be subject to mass wasting to become sediment and/or soilproximate to or at a distance of many miles from its original location.

The term “sediment,” as used herein, can refer to a granular materialeroded by forces of nature, but not yet to the point of becoming “soil.”Sediment may be found on or within the Earth's crust. A collection ofsediments is commonly referred to as a “sediment formation.” Sediment iscommonly unconsolidated, although “partially consolidated sediments” areoften referred to simply as “sediments” and are therefore considered tobe included within the definition of sediment.

The term “soil,” as used herein, can refer to a granular materialcomprising a biologically active, porous medium. Soil is found on, or aspart of, the uppermost layer of the Earth's crust and evolves throughweathering of solid materials, such as consolidated rocks, sediments,glacial tills, volcanic ash, and organic matter. Although often usedinterchangeably with the term “dirt,” dirt is technically notbiologically active.

The term “fluid,” as used herein, can refer to a liquid, gas, orcombination thereof, or a fluid that exists above the critical point,e.g., a supercritical fluid. A fluid is capable of flowing, expanding,and accommodating a shape of its physical surroundings. A fluid cancomprise a native fluid, a working fluid, or combinations thereof.Examples of fluid include, for example, air, water, brine (i.e., saltywater), hydrocarbon, CO₂, magma, noble gases, or any combinationthereof.

The term “native fluid,” as used herein, can refer to a fluid which isresident in a rock formation or sediment formation prior to theimplementation of the systems or methods of the present disclosure. Anative fluid includes, but is not limited to, water, saline water, oil,natural gas, hydrocarbons (e.g., methane, natural gas, oil), andcombinations thereof. Carbon dioxide can also be previously-present inthe rock or sediment formation and thus constitute a native fluid inthis case.

The term “working fluid,” as used herein, can refer to a fluid which isnot native to a rock formation or sediment formation and that is used bythe systems or methods of the present disclosure for some purpose. Aworking fluid can undergo a phase change from a gas to a liquid (energysource), a liquid to gas (refrigerant), or can become part of a solution(e.g., by dissolving into a native fluid). A “working fluid” in amachine or in a closed loop system can be the pressurized gas or liquidwhich actuates the machine. Water is used as a working fluid inconventional (e.g., water-based) heat engine systems. Non-water basedworking fluids can include, but are not limited to, ammonia, sulfurdioxide, carbon dioxide, and non-halogenated hydrocarbons such asmethane. A working fluid can include a fluid in a supercritical state.Different working fluids can have different thermodynamic andfluid-dynamic properties, resulting in different power conversionefficiencies.

The term “pore space” as used herein, can refer to any space notoccupied by a solid (rock or mineral). Pore space can be the spaceformed between grains or the space formed by fractures, faults,fissures, conduits, caves, or any other type of non-solid space. Porespace can be connected or unconnected and it can evolve over time due tochanges in solid space volume or size (which can come from chemicalreactions, deformations, etc.). A space can be filled with fluid andstill be deemed to be “pore space.”

The term “CO₂ plume” as used herein, can refer to a large-scale (e.g.,meters to several kilometers to tens of kilometers across) CO₂ presencewithin subsurface pore spaces. Within a CO₂ plume, a significantpercentage of fluid in the pore space can be CO₂. The CO₂ plume caninclude other fluids, such as native methane or other hydrocarbons,which can be collected and carried by the CO₂ plume as it travelsthrough a reservoir. For example, a CO₂ plume can include a substantialpercentage (e.g., as much as 20 wt. %) methane that has been desorbedfrom a saline aquifer (as described in more detail below). A CO₂ plumecan also include a substantial portion of native hydrocarbons, (e.g., upto 90 wt % hydrocarbons or more), and can still be considered a “CO₂plume” within the meaning of the present disclosure. A CO₂ plume cancontain a substantial portion, e.g., as much as 70% by volume, or more,of a native fluid such as brine or hydrocarbons extracted from areservoir. The brine or other native fluid can be immobile or onlyminimally mobile and, therefore, generally considered in the art to beresidually trapped.

The term “reservoir” or “storage rock formation” or “storage sedimentformation,” as used herein, can refer to a formation comprising one ormore of rock, sediment, and soil that can be capable of receiving andstoring an amount of fluid substantially “permanently” as that term isunderstood in the geological arts.

The term “geothermal heat flow,” as used herein, can refer to any kindof heat transfer in the subsurface and can include one or more ofconductive heat transfer, advective heat transfer (also referred to asconvective heat transfer), and radiative heat transfer (althoughradiative heat transfer can typically be negligible in the subsurface).A “low” heat flow generally can be considered to be less than about 50milliwatts per square meter. A “moderate” heat flow generally can beconsidered to be at least about 50 to about 80 milliwatts per squaremeter. A “high” heat flow generally can be considered to be greater than80 milliwatts per square meter.

The term “injection well,” as used herein, can refer to a well orborehole, which can be cased (e.g., lined) or uncased, and which cancontain one or more pipes through which a fluid can flow (typically in adownward direction) for purposes of releasing that fluid into thesubsurface at some depth.

The term “production well.” as used herein, can refer to a well orborehole, which can be cased (e.g., lined) or uncased, and which cancontain one or more pipes through which a fluid can flow (typically inan upward direction) for purposes of bringing fluids up from thesubsurface up to the Earth's surface or near the surface. A productionwell can exist in the same borehole as an injection well.

The term “enhanced geothermal system” (EGS), as used herein, can referto a system in which a manmade (e.g., artificial) reservoir is created,usually by means of large-scale hydrofracturing of the subsurface, e.g.,by inducing fractures to create space which can contain significantamounts of fluid. Such artificial reservoirs typically can be muchsmaller than natural reservoirs.

The term “enhanced oil recovery” (EOR) (also referred to as “improvedoil recovery,” “tertiary recovery.” or “quaternary recovery”), as usedherein, can refer to a system or method of recovering hydrocarbons,including, by not limited to, liquid hydrocarbons such as crude oil andhydrocarbons such as natural gas that are gaseous at atmosphericpressure and temperature, from a reservoir. EOR can include theinjection of a fluid, such as carbon dioxide, or other components intothe reservoir in order to improve extraction of the hydrocarbons, suchas by at least one of reducing the fluid viscosity, reducing the surfacetension of the hydrocarbons, or increasing pressure in the reservoir, inorder to more easily remove them from the reservoir.

The term “conventional water-based geothermal system,” as used herein,can refer to a geothermal system that uses water as a working fluid. Aconventional water-based geothermal approach can be used in naturalreservoir systems or in hydrofractured (e.g., EGS) systems.

The term “conventional CO₂-based EGS,” as used herein, can refer to aconventional EGS system that uses carbon dioxide as the working fluid.

The term “waste heat,” as used herein, can refer to heat energygenerated by a system or unit operation that typically is allowed todissipate to the environment rather than being used for some otherpurpose within the system or method.

Enhanced CPG Systems

FIG. 1 shows an example system 10 for the recovery of geothermal energyfrom a reservoir 1. The reservoir 1 can include a native fluid 2. Thenative fluid 2 can include a solution comprising methane (CH₄) 4. In anexample, the native fluid 2 can comprise a brine within a reservoir 1that is a saline aquifer. The methane 4 can be dissolved in the brine inlow concentrations. In another example, the native fluid 2 can be nativehydrocarbons, such as those in an oil field. A working fluid 12 can beinjected into the reservoir 1 via an injection well 14. The injectionwell 14 can include an injection well opening 16 that is in fluidcommunication with the reservoir 1 to allow the working fluid 12 toenter the reservoir 1.

In an example, the working fluid 12 is a non-water based working fluid12, such as carbon dioxide (CO₂). For the sake of brevity, the remainderof this disclosure will describe the working fluid 12 as CO₂ workingfluid 12. However, as described above, the working fluid 12 can compriseother suitable compounds capable of absorbing thermal energy from itssurroundings, and further releasing the thermal energy as describedherein. Other examples of non-water based working fluids 12 can include,but are not limited to, ammonia, sulfur dioxide, or non-halogenatedhydrocarbons such as methane.

The CO₂ working fluid 12 can be provided from a CO₂ source 18, such as awaste stream from a facility that produces CO₂, such as via combustion.Examples of facilities that can be a CO₂ source 18 include power plants,such as a fossil fuel power plants (e.g., coal plant, natural gas plant,and the like), a plant capable of producing fuel, such as biofuel (e.g.,ethanol plant), or an industrial plant, such as a cement manufacturer,steel manufacturer, and the like. The CO₂ source 18 can also be naturalgeologic CO₂ produced from a geologic formation. In an example, the CO₂can be transported from a remote CO₂ source 18 via any suitable means,(e.g., a pipeline or via various transportation means, such as a truck,ship, or railroad). In another example, the facility that provides theCO₂ source 18 can be co-located with the geothermal recovery system 10,such as a co-located power plant, biofuel plant, or industrial plant. Asdescribed in more detail below, a co-located facility can provide forsynergies allowing for more efficient operation of the co-locatedfacility and of the geothermal energy recovery.

In an example, the system 10 can be located at a site (e.g., in aposition) configured to provide access to a target formation. The targetformation can comprise a caprock 8 located above a reservoir 1, as shownin FIG. 1. The reservoir 1 can have a natural temperature higher than atemperature of the working fluid. The natural temperature can be causedby in-situ geothermal heat located within the reservoir or thegeological formation proximate to the reservoir. The natural temperaturein the reservoir 1 can be affected by a geothermal heat 6 flow, such asthe geothermal heat 6 flowing up from below.

A top layer 9 can be located above the caprock 8 and the reservoir 1.The top layer 9 can comprise any number of layers and types of naturaldeposits or formations. For example, the top layer 9 can comprise one ormore features such as one or more reservoirs (e.g., the reservoir 1 or adifferent reservoir) or one or more caprocks (e.g., the caprock 8)having the features as described herein. The top layer 9 canadditionally or alternatively comprise additional areas suitable forinjection of the working fluid, such as the CO₂ working fluid 12. In anexample, the top layer 9 additionally or alternatively further comprisesany type of rocks, including rocks or sediments in layers, rock orsediment formations, and the like, or any combinations thereof. The toplayer 9 can additionally or alternatively comprise a top layer or layersof sediment or soil of varying depths. The permeability and porosity ofthe top layer 9 can vary widely, as long as drilling can be performed toinsert the injection well 14 and production well 28, as described below.

The top layer 9 can include a variety of geologic features, including,but not limited to, soil, sand, dirt, sediment, and the like, orcombinations thereof. The top layer 9 can further have a wide range ofdepths (e.g., “thickness”) sufficient to ensure the working fluidintroduced into the reservoir 1 can remain in the desired state, such asa supercritical state. In an example, the depth of the top layer 9 is atleast 100 meters (m) or more, and can be up to one (1) kilometer (km) ormore, such as up to three (3) km, four (4) km, five (5) km, for example,up to 10 km or over 15 km including any range there between, below theEarth's surface (e.g., below or within a given topography in an area,which may or may not be exposed to the atmosphere). In most examples,however, it is expected that the target formations will be locatedbetween about 800 m and about four (4) km beneath the Earth's surface.

Factors that can be considered in selecting reservoir depths can alsovary according to local geology (e.g., specific rock type, geothermalheat flow rates, subsurface temperatures), access to working fluid(e.g., carbon dioxide from fossil fuel burning power plants, ethanolplants), drilling and operation costs, and sociopolitical circumstances(e.g., consumer locations, constructs, electric grid locations, and thelike).

The target formation, which can include the reservoir 1, a caprock 8,and a top layer 9, can be made up of a variety of rock types, including,but not limited to, igneous rock, metamorphic rock, limestone,sedimentary rock, crystalline rock, and combinations thereof. In anexample, the target formation is a sedimentary basin having asubstantially bowl or convex shape. In other examples, the targetformation can have another shape, such as the substantially dome orconcave shape, although the present disclosure is not limited to theshapes described or depicted in the figures. In some examples, thetarget formation is lower than the lowest freshwater aquifer, but thismay not always be the case. The target formation can comprise a brine orwater aquifer or a brine or water-filled rock formation (e.g., reservoir1) that includes a native fluid 2. The native fluid 2 can be inhibitedor prevented from escaping upwardly, for example due to the presence ofthe caprock 8. The target formation can also contain a fault which canoffset the target formation or a portion of the target formation,thereby forming a geological trap, as the term is understood in the art.In an example, the target formation is a reservoir containing one ormore of natural gas, oil, native CO₂, fresh water, or brine.

In an example, CO₂, such as the CO₂ working fluid 12 shown in FIG. 1, isused as the working fluid in combination with a reservoir 1 located atleast about 0.1 km, to about 5 km deep. Such a combination can minimizeupward leakage of the working fluid, since additional caprocks 8 can bepresent between the reservoir 1 and the Earth's surface. Additionally,higher natural reservoir temperatures (e.g., greater than about 70° C.)and higher pressures (e.g., greater than about 8 MPa) can be encounteredat such depths. Larger depths can also increase the likelihood of thepresence of dissolved salts and other minerals in the native fluid,which can reduce the likelihood that such native fluid would otherwisebe useful for drinking and irrigation applications.

If present, the caprock, such as the caprock 8 shown in FIG. 1, can be ageologic feature having a very low permeability, e.g., below about 10⁻¹⁶m². Such a low permeability can allow the caprock 8 to essentiallyfunction as a barrier for fluid contained in the reservoir 1 below.Permeability can also be dependent, in part, on the depth (e.g.,thickness) of the caprock 8, as well as the depth of the top layer 9above the caprock 8 and the reservoir 1. The porosity of the caprock 8can vary widely. As is known in the art, even if a rock is highlyporous, if voids within the rock are not interconnected, fluids withinthe closed, isolated pores cannot move. Therefore, as long as thecaprock 8 exhibits permeability sufficiently low to allow it to preventor inhibit fluid leakage from fluid in the reservoir 1, the porosity ofthe caprock 8 is not limited.

The thickness of the caprock 8 can vary, but is generally substantiallyless than the thickness of the top layer 9. In an example, the top layer9 has a thickness on the order of 10, or 10 to 100, up to 1000 times thethickness of the caprock 8, further including any range there between,although the systems and methods of the present disclosure are not solimited. In an example, the thickness of the caprock 8 can vary fromabout one (1) cm up to about 1000 m or more, such as between about five(5) cm and 100 m, such as between about one (1) m and about 100 m. Thecaprock 8 can comprise more than one caprock layer, such that multiplecaprocks can be present which partially or completely cover one anotherand can act jointly as a caprock 8 to prevent or reduce upward leakageof the working fluid from the reservoir 1.

The reservoir 1 can be one or more natural underground rock reservoirscapable of containing fluids. For example, the reservoir 1 can be apreviously-created manmade reservoir or a portion of apreviously-created manmade reservoir, such as, for example, shaleformations remaining from shale fracturing for hydrocarbon removal. Thereservoir 1 can also be capable of storing carbon dioxide on a permanentor substantially permanent basis, as this term is understood in the art.In some examples, the reservoir 1 is sufficiently porous and permeableto be able to sequester fluids, such as carbon dioxide, and to receiveand retain geothermal heat 6. In contrast to conventional geothermalsystems, such as enhanced geothermal systems using a water-based workingfluid, there is no requirement that the reservoir 1 be a hot dry rockreservoir, as that term is understood in the art, although, as notedherein, such a reservoir can optionally be used.

The reservoir 1 can be sufficiently permeable to allow multidirectionalroutes for dispersion or flow of fluid at relatively high rates,including lateral dispersion or flow. The caprock 8 above the reservoir1, if present, can further enhance the dispersion capabilities of thereservoir 1. In an example, the porosity of the reservoir 1 can rangefrom between about two (2) % to about 50% or greater, such as up toabout 60%.

The reservoir 1 can be sufficiently permeable to allow fluids to flowrelatively easily, e.g., at a rate of about 0.1 to about 50liters/minute (L/min) or higher, such as up to several thousand L/min.In an example, the reservoir 1 has a permeability of about 10⁻¹⁶ m² toabout 10⁻⁹ m², or greater, such as up to about 10⁻⁶ m².

In an example, the reservoir 1 has a porosity of at least about two (2)% and a permeability of at least about 10⁻¹⁵ m², with the caprock 8having a maximum permeability of about 10⁻¹⁶ m².

The reservoir 1 can have any suitable natural temperature. In anexample, the natural temperature of the reservoir 1 is at least about40° C., although natural temperatures below 40° C. can be sufficient,such as down to 30° C. or 20° C., further including down to 10° C.including any range there between. The ability to economically recovergeothermal energy from a reservoir 1 having a natural temperature as lowas 10° C., as described below, demonstrates a substantial advantage ofthe methane-enhanced geothermal recovery systems of the presentdisclosure over systems that use CO₂ alone for geothermal recovery, suchas CPG systems described above. Natural temperatures greater than 90° C.can also be present, with the highest temperature limited only by theamount of geothermal heat 6 provided and the ability of the reservoir 1to capture and retain the geothermal heat 6. For example, it is possiblethat temperatures greater than about 300° C. can be present in thereservoir 1.

A specific desired natural temperature can be obtained by varying thedepth of the injection well 14 or the production well 28, or both. In anexample, higher natural temperatures can be obtained by increasing thedepth of the injection well 14, with or without increasing the depth ofthe production well 28. The overall size of the reservoir 1 can alsovary.

The geothermal heat 6 can flow at any suitable rate, including at a highrate as is present in “high geothermal heat flow regions”, as the termis understood in the art. Conventional water-based systems are known torequire high geothermal heat flow in most instances. As a result, ascompared to conventional systems using water as the working fluid, thesystems described herein can operate in a wider range of locations,including low and moderate geothermal heat flow regions. Themethane-enhanced and waste-heat enhanced systems of the presentdisclosure can also operate a wider range of locations than systems thatmerely use a CO₂ working fluid to recover geothermal energy, includingat lower heat flow rates than the CO₂ geothermal-only systems. Also incontrast to conventional water-based systems which can be operated inareas containing little natural water (e.g., the American Southwest),thus requiring importation of water, the novel systems described hereindo not rely on water as the working fluid, and thus do not import waterfor use as a working fluid. It is to be understood, that areas havingmedium or low geothermal heat flow rates can also be used.

In some examples, the CO₂ working fluid from the CO₂ source 18 can becompressed to an elevated pressure in a compressor 20. In an example,the compressed CO₂ can be cooled in a cooling unit 22 because coolingthe CO₂ working fluid 12 prior to injection into the injection well 14can be advantageous by improving injectability of the CO₂. Most fluids,including CO₂, are denser when they are cooler than when they arewarmer, such that a relatively cold column of CO₂ in the injection well14 can compress itself more than a relatively hot column of CO₂.Therefore, a relatively cold and relatively low pressure CO₂ workingfluid 12 at the surface can have the same pressure at the bottom of theinjection well 14 as a relatively hot and relatively high pressure CO₂working fluid 12 fed to the injection well 14. A pump (not shown) canoptionally be included downstream of the cooling unit 22 either beforethe CO₂ working fluid 12 enters the injection well 14 or within theinjection well 14.

Although the CO₂ from the CO₂ source 18 can, in some examples, be used“as is,” in other examples, further processing of the CO₂ from the CO₂source 18 can be performed prior to introducing the CO₂ to thecompressor 20, the cooling unit 22, or the injection well 14. Forexample, some waste streams can require dewatering or drying, or both.In an example, the CO₂ from the CO₂ source 18 can be stored on site oroff site for a period of time. In an example, the cold CO₂ that is fedfrom the cooling unit 22 into the injection well 14 as the CO₂ workingfluid 12 is a saturated liquid or supercritical CO₂.

As shown in FIG. 1, the working fluid 12 can pass through the reservoir1 in the form of a CO₂ plume 24. The CO₂ working fluid 12 can cause atleast a portion of the methane 4 within the reservoir 1 to come out ofsolution from within the native fluid 2 where the methane 4 can becarried along with the CO₂ plume 24. Together, the CO₂ working fluid 12within the CO₂ plume 24 and the methane 4 can form a production fluid 26that can pass through a production well opening 30 of each of one ormore production wells 28. Each production well 28 can carry theproduction fluid 26 to or near the surface for energy recovery within anenergy recovery system 32. In some examples, the production fluid 26 canbe sent through a filter system at or near the surface to reduce orprevent particulate matter from entering any surface system components,such as those within the energy recovery system 32.

As mentioned above, in an example the native fluid 2 can comprise abrine, such as what can be present in a deep saline aquifer 1. In anexample, a saline aquifer 1 can be present proximate to a hydrocarbonfield such that a portion of the methane and other gaseous hydrocarbons,such as ethane and propane, can dissolve into the brine 2 within theaquifer 1. Although many alkane compounds can dissolve in brine, methanehas the highest solubility compared to higher-order alkanes (e.g.,ethane, propane, butane, etc.). Therefore, while other alkanes can bedissolved into solution in the brine 2, the present disclosure willdescribe the systems and methods herein as being with respect todissolved methane. In an example, the composition of methane dissolvedin the brine 2 can be from about 0.1 wt % to about 5 wt % methane. Sucha low percentage of methane generally makes the methane, by itself,uneconomical to mine. For example, the cost to extract dilute methanedissolved in a saline aquifer would generally be achieved by pumping thebrine to the surface and extracting the methane. The energy requirementto pump the brine to the surface can cost considerably more than theactual value of the methane that is extracted.

Carbon dioxide is known to have a higher solubility in brine thanmethane and other alkanes, such that when the CO₂ working fluid 12 isinjected into the aquifer 1, the CO₂ will preferentially dissolve intothe brine 2 and force at least a portion of the methane 4 out ofsolution. The dissolution of the methane 4 can create a zone ofrelatively high concentration of methane in front of the advancing CO₂plume 24. FIG. 5 (described in more detail below) shows an example ofthe formation of a zone 34 that has a high concentration of methane 4 infront of the CO₂ plume 24. The CO₂ plume 24 can force thehigh-concentration zone 34, which can also contain a substantialpercentage of brine or other native fluid 2, through the reservoir 1 andinto the one or more production wells 28. In addition, a portion of themethane 4 that has come out of solution with the brine 2 can dissolveinto the CO₂ phase to form a CO₂/methane solution plume that is advancedby or combines with the CO₂ plume 24. As described above, thecombination of the methane 4 that has come out of solution and the CO₂plume 24 is referred to herein as “production fluid 26,” whether the CO₂and methane form separate plumes, a gas mixture, or a gas solution ofmethane and CO₂. As described in more detail below, in some examples,the high-concentration methane zone 34 can also be produced separatelyfrom the CO₂ plume 24, such as via the formation of separate productionwells 28A, 28B for each.

As the production fluid 26 moves through the reservoir 2, it can becomeheated by geothermal heat 6 that is present in or is supplied to thereservoir 120. The geothermal heat 6 can raise the temperature of one ormore components of the production fluid 26, raise the pressure of one ormore components of the production fluid 26, or both. For example, thegeothermal heat 6 can raise the temperature of the CO₂ working fluid 12,the released methane 4, or both, raise the pressure of the CO₂ workingfluid 12, the released methane 4, or both, or raise both the temperatureand the pressure of the CO₂ working fluid 12 or the released methane 4,or both, within the production fluid 26. For example, the temperature ofthe production fluid 26 as it enters the production well opening 30 canbe higher than the temperature of the CO₂ working fluid 12 as it exitsthe injection well opening 16.

Upon its release at the injection well reservoir opening 16, therelatively cool CO₂ working fluid 12 can permeate through the reservoir1 forming the CO₂ plume 24. Upon exposure to the temperatures present inthe reservoir 1 (which are higher than the temperature of the cold CO₂working fluid 12), the cold CO₂ working fluid 12 absorbs heat from thereservoir 1, thus causing an upwardly-migrating CO₂ plume 24, which, inan example, can be laterally advected due to non-zero groundwater flowvelocities within the reservoir 1. In an example, lateral migrationoccurs additionally or alternatively due to the CO₂ plume 24 spreading,as additional CO₂ exits the production well 28. In an example, the CO₂working fluid 12, in the form of the CO₂ plume 24 or the productionfluid 26, can form a continuous or substantially continuous connectedstream from the injection well opening 16 to the production well opening30.

The CO₂ plume 24 can migrate, can be transported (such as in a closedloop system as described herein), or can flow or spreads towards theproduction well 28, entering a production well reservoir opening 30 as arelatively hot production fluid 26, e.g., a fluid having a temperaturegreater than the temperature of the cold CO₂ working fluid 12 at theinjection well opening 16. The CO₂ plume 24 can move at any suitablerate in a substantially horizontal manner across the reservoir 1. In anexample, the CO₂ plume 24 can move at a rate of from about 0.1 to aboutone (1) m per day, inclusive, such as from about 0.4 to about 0.6 m/day,inclusive, although the systems and methods of the present disclosureare not so limited.

In another example, the reservoir 1 can comprise a hydrocarbon field,such as a reservoir that is part of an oil or natural gas field. The oilor natural gas reservoir 1 can be partially depleted by conventionalhydrocarbon recovery methods. In such a case, if the CO₂ working fluidcan serve to assist in oil or hydrocarbon recovery through enhanced oilrecovery (EOR). An EOR system can be set up similar to the systemdescribed above for a brine saline aquifer, e.g., with a CO₂ source 18providing the CO₂ working fluid that can be injected into the reservoir1 using a compressor 20 and, in some examples, a cooling unit 22.Therefore, FIG. 1 will be used to describe an EOR system as well.

In an EOR-type system, methane 4 and other hydrocarbon gasses can be ina solution within the native fluid 2, such as by being dissolved orcomplexed with other hydrocarbons in the native fluid 2, or the methane4 can be physically stored within the reservoir 1, such as within poresof the rock formation that forms the reservoir 1. The native fluid 2 canalso comprise at least one hydrocarbon to be recovered, such as oil,natural gas, or both. The CO₂ working fluid 12 can be injected throughthe one or more injection wells 14 and into the reservoir 1, where theCO₂ working fluid 12 can interact with the native fluid 2, and inparticular can interact with the at least one hydrocarbon of the nativefluid 2, to form at least one production fluid 26. The interactionbetween the CO₂ working fluid 12 and the native fluid 2 can improve themobility of the hydrocarbons in the resulting production fluid 26 toimprove extraction of the hydrocarbons from the reservoir 2. Theproduction fluid 26 can be pushed toward one or more production wells28, where it can be returned at or near the surface.

In an example, water or other fluids can be injected into the reservoirin addition to the CO₂ or other non-water based working fluid 12. Forexample, a Water Alternating Gas (“WAG”) method can be used where theCO₂ working fluid 12 and a water-containing working fluid arealternated, with the CO₂ working fluid 12 acting to improve mobility ofthe hydrocarbons, and the water-containing working fluid pushing the CO₂and hydrocarbon production fluid 26 toward one or more production wellopenings 30 and up the one or more production wells 28. Furtherdescription of EOR and WAG is including in National Energy TechnologyLaboratory (NETL), “Carbon Dioxide Enhanced Oil Recovery,” (available athttp://www.netl.doe.gov/technologies/oil-gas/publications/EP/small_CO2_eor_primer.pdf)(March 2010) which is incorporated herein by reference in its entirety.

In the case of an EOR-type method, the production fluid 26 can includeat least a portion of the CO₂ working fluid 12 and at least a portion ofthe hydrocarbons that had been part of the native fluid 2. Theproduction fluid 26 can also include other native fluids that can bepresent in the reservoir 1, such as a brine solution, and other injectedfluids, such as a water-containing working fluid. In an example, theproduction fluid 26 can include a non-water based working fluid (e.g.,CO₂) content between about 0.01 wt % and about 99 wt %, inclusive, forexample between about 33 wt % and about 50 wt %, inclusive, of thenon-water based working fluid. The production fluid 26 can include ahydrocarbon content of between about 1 wt % and about 95 wt %,inclusive, for example between about 25 wt % and about 50 wt %,inclusive, of hydrocarbons. The production fluid 26 can include acomposition of other fluids, such as brine or an injectedwater-containing working fluid, of between about 1 wt % and about 95 wt%, inclusive, for example between about 25 wt % and about 50 wt %,inclusive, of other native fluids or other injected fluids.

Depending on the composition of the native fluid in the reservoir 1 andthe specifics of the particular EOR operation, the production fluid 26can have a“high” percentage of CO₂ from the working fluid, e.g., betweenabout 66 wt % and about 99 wt % CO₂, inclusive, a “low” percentage ofCO₂ from the working fluid, e.g., between 1 wt % and about 33 wt % CO₂,inclusive, or any range of CO₂ content in between, such as a “medium”percentage of the CO₂ working fluid, e.g., between about 33 wt % andabout 66 wt % CO₂, inclusive. In some examples, the percentage of CO₂ inthe production fluid can be very low, such as from 1 wt % to 9 wt %,inclusive, for example from 2 wt % to 5 wt %, inclusive.

In the case of a CO₂ working fluid 12, the CO₂ can be partially or fullymiscible with the hydrocarbons so that the CO₂ working fluid 12 and thehydrocarbons form a homogenous or substantially homogenous solution ofCO₂ and hydrocarbon. Alternatively, the CO₂ working fluid 12 can befully or substantially immiscible so that the CO₂ only partiallydissolves, or substantially does not dissolve in the hydrocarbons sothat the CO₂ and the hydrocarbons in the production fluid 141 areproduced as separate immiscible or substantially immiscible fluids. TheCO₂ can mix with the hydrocarbons and can provide for at least one ofreduced viscosity of the hydrocarbons, reduced surface tension of thehydrocarbons, increased mobility of the hydrocarbons, or increased fluidpressure in the reservoir 1 so that the hydrocarbons can more easilyseparate from the rock formation of the reservoir 1 or be more easilydriven toward the production well opening 30, or both.

The production fluid 26 can be carried up through the reservoir 2, suchas by or in conjunction with a CO₂ plume 24. The production fluid 26 canalso be formed as a zone of mobilized hydrocarbons and CO₂ that can besimilar to a plume, but not necessarily. In an example where awater-containing working fluid is used, such as in a WAG process(described above), the one or more production fluids 26 can includealternating zones of mobilized hydrocarbons with CO₂ and zones ofwater-containing working fluid. As the production fluid 26 moves throughthe reservoir 2, it can become heated by geothermal heat 6 that ispresent in or is supplied to the reservoir 1. The geothermal heat 6 canraise the temperature of one or more components of the production fluid26, raise the pressure of one or more components of the production fluid26, or both. For example, the geothermal heat 6 can raise thetemperature of at least one of the CO₂ working fluid 12, the methane 4released from the native fluid 2, or other hydrocarbons released fromthe native fluid 2, raise the pressure of at least one of the CO₂working fluid 12, the methane 4 released from the native fluid 2, orother hydrocarbons released from the native fluid 2, or raise both thetemperature and the pressure of at least one of the CO₂ working fluid12, the methane 4 released from the native fluid 2, or otherhydrocarbons released from the native fluid 2. For example, thetemperature of the production fluid 26 as it enters the production wellopening 30 can be higher than the temperature of the CO₂ working fluid12 as it exits the injection well opening 16.

The dissolving of at least a portion of the CO₂ working fluid 12 into abrine working fluid 2 can provide for CO₂ sequestering. e.g., to storeCO₂ that has been produced in a power plant, a biofuel plant, or anindustrial plant in order to reduce CO₂ emissions into the atmosphere.Similarly, a portion of the CO₂ working fluid 12 can be sequestered intoan oil or hydrocarbon reservoir 1 when the CO₂ working fluid 12 is beingused for EOR

Whether the native fluid 2 comprises a fluid with dissolved methane,such as a brine, or a hydrocarbon fluid, such as oil or natural gas inan EOR field, the production fluid 26 can be brought to the surface viathe one or more production wells 28 so that energy can be recovered viaan energy recovery system 32. In an example, shown in FIG. 1, the energyrecovery system 32 can comprise an expansion device 36. The expansiondevice 36 can provide shaft power 38 to a generator 40, which in turncan generate electricity 42. Because the expansion device 36 in FIG. 1is being directly driven by the production fluid 26 that is being heatedby the geothermal heat 6, the system of FIG. 1 can be referred to as adirect expansion device system, or more commonly a direct turbinesystem.

The system 10 can include a pump or compressor (not shown) at thesurface, e.g., essentially immediately downstream of the production well28, and upstream of the energy recovery system 32, in order to boost thepressure of the production fluid 26. The increased pressure from thispump or compressor can allow the production fluid 26 to effectively andefficiently produce power when the production fluid 36 is run throughthe expansion device 36. A pump or compressor in this location, e.g.upstream of the energy recovery system 26, can be particular effectivefor a reservoir 1 comprising a saline aquifer with native CO₂ in thenative fluid 2, because the production fluid 26 can be produced atpressures that are too low to cost-effectively produce electricity 42from the expansion device 36 and the generator 40. Waste heat off thispump or compressor can be harvested, as described in more detail below,for supplementing power production. Alternatively, a pump or compressorcan be added to the system essentially immediately upstream of theinjection well 14 before reinjection the CO₂ into the reservoir 1 aspart of the working fluid 12.

The expansion device 36 can comprise any suitable type of expansiondevice 36 known in the art, such as a turbine, although the presentdisclosure is not so limited. In contrast to conventional water-basedgeothermal systems which produce low pressure steam at high volumetricflow rates, the use of a conventional turbine in higher pressure CO₂geothermal energy systems and methods described herein, is an option,rather than a requirement

In an example, the expansion device 36 comprises one or morepiston-cylinder devices. The expansion device 36 can be one or morescroll, screw or rotary compressors designed to run in reverse asengines. The expansion device 36 can comprise a single expansion device36, or a plurality of expansion devices 36. Multiple expansion devices36 can run in parallel, with one or more first expansion devices 36running pumps or compressors directly and one or more second expansiondevices 36 producing electric power for sale. The generator 40 can beany suitable generator known in the art, to produce electricity 42. Inan example, the components of the production fluid 26 can compriseprimarily or substantially all of lower density gases so that theexpansion device 36 can be a direct turbine. Relatively low-densitygaseous or supercritical fluids can provide relatively higher energyefficiency, and thus produce relatively more energy in the form ofelectricity, than higher density fluids in liquid phase when decreasingbetween the same pressure levels. Passing a low density fluid, such asCO₂ and methane, through a direct turbine generally can produce moreelectricity than extracting thermal energy to operate an Organic RankineCycle or other binary system, and then decreasing the pressure through avalve or turbine, when operating between the same inlet and exitconditions.

As described above, the native fluid 2 in the reservoir 2 can comprisemethane 4, such as methane 4 within solution in the native fluid 2. Asfurther described above, the injection of the CO₂ working fluid 12 cancause at least a portion of the methane 4 to come out of solution withthe native fluid 2 and be brought up to the surface with the CO₂ workingfluid 12 as a production fluid 26. The system and method of the presentdisclosure can be configured to take advantage of the methane 4 that isproduced to the surface in order to improve the efficiency of thegeothermal energy recovery by recovering another form of energy from thereservoir 1—namely, a portion of the chemical energy stored in themethane 4.

As shown in FIG. 1, the system 10 can include a separation system 44that can be configured to separate a portion 46 of the methane from aproduction fluid comprising CO₂ and methane. The separated methane 46can be combusted to increase the temperature of the production fluid 26,the pressure of the production fluid 26, or both. In an example, atleast a portion of the separated methane 46 can be fed into a heater 48that can heat the production fluid 26, or increase the pressure of theproduction fluid 26, or both, to form a heated and/or pressurizedproduction fluid 50.

After combustion in the heater 48, the methane 46 is converted into CO₂and water vapor in an exhaust stream 56. In an example, at least aportion of the CO₂ in the exhaust stream 56 can be captured by a CO₂capture system 58. In an example, the CO₂ capture system 58 can comprisean absorber through which an absorbing material can flow, such as anabsorbing solution comprising one or more amines, and a regenerator thatcan strip CO₂ from the amine solution. The outputs from the CO₂ capturesystem 58 can include a CO₂-rich stream 60 and a vented gas 62 (e.g.,water vapor and other non-absorbed compounds). If desired, the ventedgas 62 can be further treated. The CO₂ output stream 60 can be fed backinto the reservoir 1, such as by compressing the CO₂ output stream 60 ina compressor, which can be the same compressor 20 as is used to compressthe CO₂ from the CO₂ source 18, as shown in FIG. 1, or it can be adifferent compressor.

In another example, rather than heating the production fluid 26 with aheater 48, the separated methane 46 can be combusted in a conventionalgas turbine or gas engine (not shown) to produce electricity from theturbine or engine. The combustion of the methane 46 in the gas turbineor the engine can produce substantial waste heat in the form of hotcombustion gases (e.g., CO₂ and steam) and hot engine or turbine coolingjacket fluid. The waste heat can be added to the production fluid 26,such as via a heat exchanger. This configuration can, in some cases,lead to higher energy conversion efficiency then directly heating theproduction fluid 26 in a heater 48.

In some examples, a portion of the separated methane 46 can be split offfrom the methane stream 46 and stored or sold as a methane product 47.However, in some situations, it may be inefficient or uneconomical tosell a portion of the separated methane 46 rather than combusting all ofthe methane 46 to boost the temperature or pressure of a working fluidor production fluid. The reason for this is because the most likely endpoint for sold methane is a natural gas power plant where it will beburned to produce electricity. As described above, the separated methane46 combusted in the heater 48 is used to heat a working fluid orproduction fluid, which in turn can be sent through an energy recoverysystem 32 to generate electricity 42. However, the sold methane 47 canlose some economic efficiency due to transportation costs to bring themethane 47 to the outside power plant. Burning methane in a power plantcan also be less efficient than the energy recovery system 32 becausepower plants do not also incorporate geothermal energy recovery.Moreover, natural gas power plants typically employ steam turbines,which can be considerably less efficient than direct turbines usingsupercritical CO₂ as the working fluid or CO₂ and methane as aproduction fluid. In addition, the majority of natural gas power plantsare not equipped for CO₂ capture so that the methane 47 delivered tothese power plants will likely contribute to CO₂ emissions. In contrast,the energy recovery systems 32 of the present disclosure can also beconfigured with a CO₂ capture system 58, as described above, to captureany CO₂ formed by the heater 48. Thus, the systems of the presentdisclosure can provide for reduced CO₂ emissions to the atmosphere. Evenif the outside power plant were to have CO₂ capturing capabilities, thesystems and methods of the present disclosure can provide for moreefficient reduction of emissions because the CO₂ capture system andgeologic storage of CO₂ can be co-located with the geothermal energyrecovery system, reducing or eliminating the need for transportationsystems necessary to reduce or prevent emissions from natural gas powerplants.

The heater 48 can be positioned upstream of the expansion device 36, asshown in FIG. 1, so that the heated and/or pressurized production fluid50 is formed prior to the production fluid 50 being fed into theexpansion device 36. After passing through the expansion device 36, theheated and/or pressurized production fluid 50 can become a slightlycooled production fluid 52.

In some examples, the separation system 44 can cool or depressurize theproduction fluid in order to achieve the separation of the methane 46(described in more detail below). Therefore, in an example, the methaneseparation system 44 is downstream of the expansion device 36 such thatthe cooled production fluid 52 is fed into the separation system 44. Byseparating the methane 46 from the production fluid 52 downstream of theexpansion device 36, the system can prevent or reduce the loss ofgeothermal energy during the separation of the methane 46 from theproduction fluid 52.

In an example, the methane separation system 44 can comprise one or moremembranes that are configured to selectively allow the passage of one ormore components within the production fluid 52 through the membranewhile preventing or impeding the passage of one or more other componentswithin the production fluid 52 through the membrane. For example, themembrane can be selectively permeable between CO₂ and methane, so thatthe CO₂ can pass substantially unimpeded through the membrane, while aportion of the methane 46 is prevented from passing through themembrane, or vice versa. In an example, the pressure difference acrossthe membrane can be controlled, which can control the percentage ofmethane that can be removed from the production fluid 52 in order tocontrol the amount of methane in the separated methane stream 46.

It has been found that even if only a small percentage of the methane isseparated from the production fluid can provide for substantialincreases in energy recovery from the energy recovery system 32. In anexample, the production fluid contains about 5 wt % methane, and about10 wt % to about 30 wt % of this can be separated out and combusted,which can provide for an increase in the production of electricity 42 offrom about 75% to 1000% above the electricity that can be produced fromthe geothermal energy collected by the production fluid alone. Moreover,separating only a small portion of the methane from the production fluidcan ensure that a substantial amount of methane is still present in theproduction fluid before it is re-injected back into the reservoir 1(described in more detail below). The presence of methane in there-injected production fluid can ensure that methane is present in thereservoir to be extracted over time such that there is a generallyalways a portion of methane that can be brought to the surface with theproduction fluid 26.

The use of the separated methane 46 can allow for economically viablegeothermal energy recovery from reservoirs having lower temperaturesthan can be achieved through simply extracting the thermal energy fromthe production fluid 26. For example, a CO₂ plume 24 is used to collectgeothermal energy, with no combustion of produced methane or any otherheat-recovery methods (such as those described below), the recovery ofgeothermal energy from the reservoir may only be economically efficientat temperatures down to between about 30° C. and about 50° C., and inmost cases only down to about 60° C. However, with the use of themethane separation system 44 and the methane combustion heater 48,economically viable recovery of geothermal energy can be achieved downto a reservoir temperature of about 10° C. to about 25° C., depending onthe percentage of methane that can be produced from the reservoir 1, thereservoir depth and temperature, and the local ambient temperature.

As noted above, the system 10 of the present disclosure can be used forgeothermal energy capture, as described herein, and can also be used forsequestering CO₂ within the rock formation or native fluid 2 within thereservoir 1. Therefore, in some examples, at least a portion of the CO₂working fluid 12 can be stored permanently or semi-permanently withinthe reservoir 1, such that a replacement supply of CO₂ can be requiredin order to continue operation of the system. The capture of the CO₂output stream 60 from the exhaust stream 56 can provide for asubstantial portion of the make-up CO₂ required. In an example, the CO₂output stream 60 from the CO₂ capture system 58 can provide all orsubstantially all of the CO₂ required to make up for CO₂ that issequestered within the reservoir 1. FIGS. 2-4 show examples of indirectenergy recovery systems that can be used for the purpose of recoveringenergy from the production fluid 26. Each of FIGS. 2-4 shows theproduction fluid 26 being passed through a heat exchanger 62 in order toheat a secondary working fluid 64. The secondary working fluid 64 can besent through one or more energy conversion devices. The systems of FIGS.2-4 are often referred to as “binary systems” because they use twoworking fluids, rather than one.

FIG. 2 shows an example energy recovery system 66 where a portion of theenergy from the secondary working fluid 64 is drawn off as heat 68. Theheat 68 can be used in any suitable direct-use applications, such asspace heating. The secondary working fluid 64 can then be sent throughan expansion device 70 to produce shaft power 72 that can be provided tothe compressor 20 for compressing the CO₂ from the CO₂ source 18 or theCO₂ output stream 60, or both. After passing through the expansiondevice 70, the additional heat 68 can be extracted for the direct-useheat applications. The secondary working fluid 64 can be cooled in asecondary cooling unit 74 before sending the secondary working fluid 64back into the heat exchanger 62 in order to complete the cycle of thesecondary working fluid 64.

FIG. 3 shows another example energy recovery system 78 where both heat80, e.g., for a direct-use application, and electricity 82 can begenerated from the secondary working fluid 64. In the example of FIG. 3,the working fluid 64 can be passed through an expansion device 84,similar to the expansion device 70 in FIG. 2, where at least a firstportion of the shaft power 86A from the expansion device 84 is used todrive a generator 88 to produce the electricity 82. A second portion ofthe shaft power 86B from the expansion device 84 can be used to assistin driving the compressor 20.

FIG. 4 shows another example energy recovery system 92, where a portionof the energy in the secondary working fluid 64 can be recovered aselectricity 90 in a method similar to that described above with respectto FIG. 3, and another portion of the energy from the secondary workingfluid 64 can be provided as heat to a separate power cycle 94 havingcomponents as understood in the art, such as a Rankine power cycle, anOrganic Rankine Cycle (ORC), or a Kalina Cycle. With a separate powercycle 94, the condensing pressure can be subcritical and the highestpressure during the heat addition can be either supercritical orsubcritical.

Each of the binary systems 66, 78, 92 of FIGS. 2-4 can provide forseparation and combustion of a portion of the methane within theproduction fluid 26 in order to supplement energy recovery from thereservoir 1. For example, in FIG. 2, after the production fluid 26 ispassed through the heat exchanger 64, the production fluid can be passedthrough a methane separation system 96 that can be similar to themethane separation system 44 described above with respect to FIG. 1. Themethane separation system 96 can separate off a portion 98 of themethane within the production fluid, which can be supplied to acombustion heater 100. In an example, the combustion heater 100 can beconfigured to heat the circulating secondary working fluid 64 before itenters the expansion device 70. In the example shown in FIG. 2, the heat68 is drawn off of the secondary working fluid 64 after heating thesecondary working fluid 64 with the methane combustion heater 100 andafter passing the secondary working fluid 64 through the expansiondevice 70. However, the system is not so limited, and the heat 68 can bedrawn off from the secondary working fluid 64 before heating with themethane combustion heater 100 or before passing the secondary workingfluid 64 through the expansion device 70.

In the example of FIG. 3, the separated methane 98 from the separationsystem 96 can be fed to a heater 102 that is configured to heat theproduction fluid 26 before it is fed into the heat exchanger 62. FIG. 4shows an example where both the production fluid 26 before the heatexchanger 62 and the secondary working fluid 64 before the expansiondevice 84 are heated with combusted methane 98 separated with a methaneseparation system 96. In the example shown in FIG. 4, a first combustionheater 104 is supplied with a first portion 98A of the separated methaneto heat the production fluid 26, and a second combustion heater 106 issupplied with a second portion 98B of the separated methane to heat thesecondary working fluid 64. In another example (not shown), both theproduction fluid 26 and the secondary working fluid 64 can be heatedwith a single, common combustion heater.

As with the heater 48 in FIG. 1, the exhaust gas from each of theheaters 100, 102, 104, and 106 can be sent through a CO₂ capture systemin order to capture the CO₂ from the combustion of the methane 98 inorder to inject the separated CO₂ into the reservoir 1. CO₂ capture andrecirculation to the compressor is not shown in FIGS. 2-4, but a personof ordinary skill in the art will understand that a CO₂ capture systemcan be implemented.

The methane separation system 44, 96 can separate the methane stream 46,98, as described above, and can leave a final production fluid 108 thatcan comprise CO₂ and methane. The final production fluid 108 can alsoinclude other compounds, such as oil and gas compounds from an EORreservoir or entrained brine solution from a saline aquifer, that can befurther separated from the final production fluid 108 and sold asseparate products, or the other compounds can be injected back into thereservoir 1 or into another reservoir. In an example, further cooling ofthe final production fluid 108 can be needed such that the finalproduction fluid 108 is sent through a cooling unit, such as a coolingtower to further cool the production fluid before re-injecting theproduction fluid back into the reservoir. In an example, the finalproduction fluid 108 can be cooled with the same cooling unit 22 thatcan cool compressed CO₂ coming of the compressor 20. The systems ofFIGS. 2-4 can include a pump (not shown) can optionally be includeddownstream of the cooling unit 22 either before the CO₂ working fluid 12enters the injection well 14 or within the injection well 14.

Alternatively, the other compounds, such as oil and gas compounds orbrine solution, can be separated from the production fluid 26 after itis produced from the production well 28 but before the energy recoverysystem 32, 66, 78, 92. In such a case, the production fluid 26 can beseparated into various component streams, such as a CO₂ and methanestream, a hydrocarbon stream, and a brine stream. Each of the componentsstreams will include geothermal heat extracted from the reservoir 1.Therefore, thermal energy can be extracted from each stream with aseparate energy recovery system, such as an expansion device andgenerator, as described above with respect to FIG. 1, or as a binarysystem, as described above with respect to FIGS. 2-4. The energyrecovery system that is employed for each stream can therefore betailored to the particular characteristics of the stream. For example,for a CO₂ and methane stream, a direct turbine system can be appropriatebecause it is generally the most efficient for low-density,supercritical or gaseous working fluids. In contrast, for a hydrocarbonstream or a brine stream, a binary system may be more appropriate andefficient. Therefore, in the case where the production fluid 26comprises multiple compounds that are to be separated, the energyrecovery system can be design to be the most economically efficient foreach particular stream.

The physical and thermodynamic properties of CO₂ and methane, which canbe the two primary components in the production fluid 26, can allow forthe final production fluid 108 to be re-injected into the reservoir 1via the injection well 14 without the need for an injection pump. Inother words, the system 10 can be configured so that the CO₂ workingfluid 12/production fluid 26, 108 can form a thermosiphon as itcirculates through the reservoir 1, to the surface via the productionwell 28, through the energy recovery system 32, 66, 78, 92, and backinto the injection well 14.

In the case of CO₂ and methane, a thermosiphon can be formed due to theexpansion properties of the gases as they are heated in the reservoir 1.In an example, a relatively cold and compressed CO₂ working fluid 12(which can include methane within the re-injected final production fluid108) is injected into the injection well 14, forming a long column ofcold fluid. As the depth into the well is increased, the fluid at aparticular point within the injection well becomes more and morecompressed, until the CO₂ working fluid exits the injection well 14 as aheavy, dense fluid from the injection well opening 16. As describedabove, at least a portion of the CO₂ working fluid 12 can form a CO₂plume 24 (which can include re-injected methane, un-dissolved methane 4,and other compounds from the native fluid 2). The CO₂ plume 24 can forma connected link between the injection well opening 16 and theproduction well opening 30. As the CO₂ plume 24 moves through thereservoir 1, it can be heated by the geothermal heat 6 within or flowinginto the reservoir 1. Both CO₂ and methane expand substantially as theyare heated, e.g., on the order of about a 100% expansion per 100° C. forCO₂ and about a 20% expansion per 50° C. for methane.

The limited space in the reservoir 1 for expansion can cause the CO₂plume 24 to become more and more compressed as it moves through thereservoir 1 from the injection well 14 to the production well 28. Thiseffect can partially offset the pressure loss due to Darcy flow as theCO₂, methane, and other fluids move through the reservoir. Therefore,once the CO₂ plume 24 reaches the production well opening 30 as theproduction fluid 26, it is a relatively hot relative to the CO₂ workingfluid 12 at the injection well opening 16, and has a pressure lossbetween the injection well opening 16 and the production well opening 30that is smaller than would be expected from an identical reservoir usingother working fluids, such as water or brine. As the production fluid 26moves up the production well 28, it expands or becomes less dense (e.g.,because there is less and less gas on top of the production fluid 26 asit moves up the production well 28), but still is at a relatively hottemperature and a relatively high pressure. In an example, theproduction fluid 26 expands less as it moves up the production well 28than the CO₂ working fluid 12 compresses as it moves down the injectionwell 14.

The injection well 14, production well 28, and the various components ofthe energy recovery system 32, 66, 78, 92 can be configured so that athermosiphon can form between the production well 28 and the injectionwell 14 so that the final production fluid 108 can be re-injected intothe injection well 14 without the use of a separate pump (as shown inFIG. 1, where the final production fluid 108 can be re-injected into theinjection well 14 immediately after the cooling unit 22, without needingto use the compressor 20). In some examples, the system parameters thatcan be adjusted to provide for a thermosiphon can include the size ordiameter of the wells 14, 28, which can determine the frictional lossesas the CO₂ working fluid 12 and production fluid 26 flow through theinjection well 14 and production well 28, and the pressure drop acrossthe equipment through which the production fluid 26 flows, particularlythe expansion device 32 in a direct turbine system or the heat exchanger62 in a binary system.

A thermosiphon or thermosiphon-like system, as described above, canprovide efficiency advantages over systems using other working fluids.For example, the formation of a CO₂ and/or methane thermosiphon canreduce or minimize parasitic power loses, such as those that can occurdue to fluid injection or production pumps. Such parasitic power losesfrom pumps or compressors can account for as much as 30% or more of thegross power generated in geothermal systems using other working fluids,such as a water-based geothermal recovery system. The ability to providefor a thermosiphon can be a particular advantage for a CO₂ working fluid12 and the methane that can be included in the production fluid 26 overother working fluids, particularly water-based geothermal systems wherea thermosiphon is impossible, practically speaking.

The presence of a pump or compressor essentially immediately downstreamof the production well 28, as described above, does not prevent thefunction of a thermosiphon or thermosiphon-like operation of the system.Rather, the pump or compressor can merely improve efficiency of thepower production in the energy recovery system 32, 66, 78, 92. A pump orcompressor upstream of the energy recovery system 32, 66, 78, 92 can bedesirable when the produced CO₂ temperature is very low, e.g.,temperatures that are far lower than conventional geothermal caneconomically support, such as temperatures less than about 75° C.). Thepump or compressor may be economically viable when supplemental heat,either waste heat or heat from combusted fuel, is added to theproduction fluid 26 between the upstream pump or compressor and energyrecovery system 32, 66, 78, 92.

The residual saturation of the brine native fluid 2 in the reservoir 1can affect the lifespan of methane production from the system. As usedherein, the term “residual saturation” can refer to the fraction of thereservoir pore space that remains occupied by the brine or water nativefluid 2 after the CO₂ working fluid 12 is injected into the reservoir 1to form the CO₂ plume 24. The residual brine or water native fluid 2 caninclude dissolved methane 4, and this methane 4 can diffuse out ofsolution over time and be carried or pushed by the CO₂ plume 24. Theresidual water or brine native fluid 2 can also prevent circulation ofthe CO₂ working fluid 12 through the portions of the reservoir 1 thatare occupied by the residual native fluid 2 while still permittingexchange of geothermal heat 6 from the reservoir 1 and residual nativefluid 2 to the CO₂ working fluid 12. Thus, the residual saturation ofthe brine native fluid 2 can, in practice, increase the percentage ofthe reservoir 1 that is occupied by a given volume of the CO₂ workingfluid 12. Therefore, the residual native fluid 2 can, in essence,increase the volume of the rock formation in the reservoir 1 that iscontacted by the CO₂ working fluid 12, which in turn can increase theamount of geothermal energy that can be captured by the CO₂ workingfluid 12. Moreover, the methane 4 that is released from solution fromthe residual brine or water means that the reservoir 1 can continue toproduce methane while increasing the volume of the rock formation thatis contacted by the CO₂ working fluid 12, thus increasing the methaneproduction and the geothermal energy recovery efficiency of the system.For this reason, residual saturation can provide a substantial featureof the methane-enhanced systems of the present disclosure.

As described above, when the CO₂ working fluid 12 is injected into thereservoir 1 where methane 4 and other alkanes are in a solution in thenative fluid 2, the CO₂ can cause a portion of the methane 4 to come outof solution where the methane can interact with the advancing CO₂ plume24. The release of the methane 4 from the solution can result in theformation of a zone of high methane concentration in front of theadvancing CO₂ plume 24. FIG. 5 shows a conceptual view of such ahigh-concentration methane zone 34 in front of the advancing CO₂ plume24. A portion of the released methane 4 can dissolve within or mix withthe CO₂ plume 24, however, the high-concentration zone 34 can includemore methane by weight % than is present in the CO₂ plume 24. In anexample, in order to maximize methane extraction from the reservoir 1,the production wells 28 can be configured to include one or more firstproduction wells 28A that are located relatively close to the injectionwell 14 and one or more second production wells 28B that are locatedfurther from the injection well 14. In the example shown in FIG. 5, thefirst production wells 28A so that the production well openings 30A(shown as horizontal production wells 28A in FIG. 5) are located withinthe CO₂ plume 24 that includes CO₂ and methane that is mixed with ordissolved into the CO₂. The second production wells 28B can bepositioned so that the production well openings 30B (shown as verticalproduction wells 28B in FIG. 5) are within the high-concentrationmethane zone 34.

The first production wells 28A, which can also be referred to herein as“CO₂ production wells 28A,” can include a production fluid comprisingCO₂ and a small portion of methane. The production fluid from the CO₂production wells 28A can be processed in substantially the same mannersas described above with respect to the production fluid 26 in FIGS. 1-4,e.g., by separating off at least a portion of the methane present in theproduction fluid to supplement the geothermal energy absorbed by theproduction fluid prior to sending the production fluid to an energyrecovery system.

The second production wells 28B, which can also be referred to herein as“methane production wells 28B,” can produce a combination of methane andbrine solution from the reservoir 1. The production fluid from themethane production wells 28B can also include some CO₂ and, in someexamples, other native fluids, such as hydrocarbons from an EORreservoir. Because the openings 30B to the methane production wells 28Bare designed to be within the high-concentration methane zone 34 withinthe reservoir 1, the produced fluid from the methane production wells isexpected to be primarily methane, with brine solution also comprising asizable portion of the production fluid.

The separate recovery of the production fluid from the CO₂ plume 24(primary CO₂ with a small portion of methane) from the CO₂ productionwells 28A and from the high-concentration methane zone 34 (primarilymethane with a small portion of brine) from the methane production wells28B can provide for more controlled extraction of methane and CO₂ andfor maximum methane extraction from the reservoir 1. However, as will beappreciated by a person of ordinary skill in the art, as the CO₂ plume24 expands within the reservoir 1, the high-concentration methane zone34 can move past the methane production wells 28B. Therefore, a stagedapproach for the placement and drilling of the production wells 28 canbe used to continue to provide for the separate production of CO₂ fromCO₂ production wells 28A and of methane from methane production wells28B.

FIG. 6 is a map view showing an example well placement for a stagedproduction using separate CO₂ production wells and methane productionwells. As shown in the example of FIG. 6, an initial injection well 114is drilled in a generally central location within a field 110. A set ofinitial arc production wells can be drilled on either side of theinjection well 114. In an example, each set of production wells caninclude a first, CO₂ production well 116A, and a second, methaneproduction well 116B. In an example, at the start up of the system, onlythe injection well 114, CO₂ production wells 116A, and methaneproduction wells 116B are drilled.

A CO₂ working fluid can be injected into the injection well 114, asdescribed above, so that a CO₂ plume forms within the undergroundreservoir. As further described above, the CO₂ working fluid can causemethane to come out of solution such that a zone of high methaneconcentration forms in front of the CO₂ plume. The CO₂ production wells116A can be positioned relative to the injection well 114 so that a CO₂production well opening is located within the CO₂ plume during aninitial operating period after start up. The methane production wells116B can be positioned relative to the injection well 114 so that amethane production well opening is located within the zone of highmethane concentration during an initial operating period after start up.In an example, the CO₂ production wells 116A are spaced from theinjection well 114 at about 100 m to about 2000 m. Each methaneproduction well 116B can be spaced another 10 m to about 1000 m from acorresponding CO₂ production well 116A.

As the CO₂ working fluid is added to the reservoir from a CO₂ source,from circulating CO₂, or from CO₂ capture off the methane combustionheater, the CO₂ plume will grow over time. After an initial operatingperiod, the CO₂ plume will reach the methane production wells 116B andthe zone of high methane concentration will be pushed beyond the firstmethane production wells 116B. At such time, a second set of productionwells can be drilled, such as a second pair of arc CO₂ production wells118A and a second pair of arc methane production wells 118B. In theexample shown in FIG. 6, the first set of production wells (e.g., CO₂production wells 116A and methane production wells 116B) can bepositioned along a first axis with respect to the injection well 114(e.g., east to west through the injection well 114, as shown in FIG. 6).The second set of production wells (e.g., CO₂ production wells 118A andmethane production wells 118B) can be positioned along a second axiswith respect to the injection well 114, wherein the second axis can begenerally perpendicular to the first axis (e.g., north to south throughthe injection well 114, as shown in FIG. 6). The additional productionwells 118A, 118B and larger CO₂ plume can support a larger CO₂circulation rate through the reservoir. One or more additional injectionwells 120 can be drilled to accommodate the additional CO₂ circulation.In an example, the added injection wells 120 can be positioned along thesecond axis relative to the initial injection well 114. The addedinjection wells 120 can be spaced from the initial injection well 114with approximately the same spacing as the CO₂ production wells 116A arespaced from the injection well 114, e.g., at about 100 m to about 2000m. Similarly, the second CO₂ production wells 118A can be spaced fromthe added injection wells 120 with approximately the same spacing, e.g.,at about 100 m to about 200 in, with the second methane production wells118B being spaced from the CO₂ production wells 118A at about 10 m toabout 1000 m.

As the CO₂ plume continues to grow, the CO₂ plume can reach the methaneproduction wells 118B such that additional production wells may bedrilled. For example, a third set of production wells, such as third CO₂production wells 122A and third methane production wells 122B can bedrilled. In an example, the third production wells (e.g., CO₂ productionwells 122A and methane production wells 122B) can be positioned alongthe first axis (e.g., the same axis as the first production wells 118A,118B), or can be positioned along another axis with respect to theinjection well 114. In an example, each third CO₂ production well 122Acan be spaced from a corresponding first CO₂ production well 116A byapproximately the same spacing as the first CO₂ production well 116A isspaced from the injection well 114, e.g., at about 100 m to about 2000m. Each third methane production well 122B can be spaced from acorresponding third CO₂ production well 122A at about 10 m to about 1000m.

As noted above, the primary components from the methane production wells28B, 116B, 18B are expected to be methane and brine solution, which willgenerally be in separate phases at the surface (e.g., gaseous methaneand liquid brine solution). Therefore, separation of methane from theproduction fluid of the methane production wells 28B, 116B, 118B can berelatively easy and inexpensive. A portion of the methane from themethane production wells 28B, 116B, 118B can be added to the combustionheater, along with any methane separated from the CO₂ production wells28A, 116A, 118A, to supplement the geothermal energy recovered by anenergy recovery system. A portion of the methane from the methaneproduction wells 28B, 116B, 118B can also be stored or re-injected intothe reservoir to ensure methane availability over the lifespan of thereservoir, wherein the re-injected methane can later be produced withCO₂, separated, and combusted to supplement geothermal energy recoveryfrom the reservoir.

Any CO₂ that is produced from the methane production wells 28B, 116B,118B can be sent through the energy recovery system, if the temperatureand/or pressure of the CO₂ from the methane production wells 28B, 116B,118B is sufficiently high. Alternatively, the CO₂ produced form themethane production wells 28B, 116B, 118B can be compressed, such as incompressor 20, and injected into the injection wells 14, 114, 120 alongwith the CO₂ working fluid 12.

Any brine or other liquid produced from either the CO₂ production wells28A, 116A, 118A or the methane production wells 28B, 116B, 118B can beprocessed with an energy recovery device, such as an expansion device, abinary energy recovery system, or a heat exchanger, to recovergeothermal energy that has been absorbed by the brine or other liquids.In most examples, unless the brine has a sufficiently high temperature,heat can be recovered from a brine solution only through a binary powersystem, such as an organic Rankine cycle (ORC) or a Kalina cycle. If thetemperature of the brine solution is at least about 165° C., andpreferably at least about 200° C., then a direct flash or dual-flashpower system can be employed. In certain examples, it may be desirableto combust a portion of the methane extracted from the reservoir 1 inorder to boost the temperature of the brine solution in addition toincreasing the temperature and/or the pressure of the CO₂ productionfluid. However, in general, water-based power systems are less efficientthan gas-based power systems, and particularly CO₂-based power systems.In some examples, after geothermal heat has been extracted from thebrine solution, the brine system can be disposed of, such as byinjecting the brine solution into the reservoir 1 or another geologicalformation, or the brine solution can be used for another purpose withinthe system, such as a cooling medium within the cooling unit 22.Alternatively, the brine solution can be processed to extract usefulminerals or to provide fresh water.

In order to maximize methane production and ensure methane is availablefor the lifespan of the system, careful and staged CO₂ plume developmentcan be employed. A single geologic reservoir that is capable ofsupporting CO₂ injection and sequestration can, for instance, havemultiple sublayers that can preferentially permit CO₂ flow. Sublayerscan be distinguished by permeability and porosity. Sublayers thatfavorably support CO₂ injection via relatively high permeability orporosity, or both, can be near-vertically separated from sublayers oflower permeability, porosity, or both. Such sublayers that support orretard CO₂ flow can alternate in any order in a near-vertical stack,where “near-vertical,” as used herein, can refer to the geologic layersand sublayers being substantially horizontally oriented, or onlyinclined from horizontal by from zero to a few degrees in deep naturallypermeable and porous formations. Such sublayering is common in deeppermeable formations. The sublayer can allow CO₂ injection andproduction to begin in one sublayer and then proceed to others. e.g. byperforating and completing the injection wells, or the production wells,or both, for the CO₂ plume (which can include methane plume, asdescribed above) in one sublayer, and with a methane high-concentrationzone, in another sublayer as each sublayer matures. In such a way, along-term methane supply for operation of the geothermal energy recoverysystem can more readily be achieved.

The examples described above with respect to FIGS. 1-6 have all shown ordescribed a single reservoir that includes a native fluid comprisingmethane in solution, where the CO₂ working fluid injected into thereservoir both extracts a portion of the methane and absorbs geothermalheat. However, other systems and methods can be included with theconcepts of the present disclosure. For example, a geological formationcan include a first geological formation in close proximity to a secondgeological formation. The first geological formation can comprise anative fluid that includes methane, while the second geologicalformation can comprise conditions that are favorable to geothermal heatabsorption into a CO₂ working fluid, or for CO₂ sequestering, or both.For example, the first, methane-containing formation can be locatedabove or below the second, geothermal heat formation. With such ageological configuration, a first set of one or more injection wells andone or more production wells can be drilled for the first formation, anda second set of one or more injection wells and one or more productionwells can be drilled for the second formation. A small amount of CO₂working fluid can be injected into the first formation to extractmethane therefrom, while a larger amount of CO₂ working fluid can beinjected into the second formation for geothermal heat recovery or CO₂sequestering, or both. The circulating CO₂ working fluid in the firstformation can supply methane for the system, while the circulating CO₂working fluid in the second formation can be used for geothermal heatrecovery, e.g., via the formation of a CO₂ plume, or for sequestering atleast a portion of the injected CO₂, or both.

As discussed above, the production fluid 26 being produced from thereservoir 1 can have a percentage of methane included within theproduction fluid 26, e.g., from 1 wt % to 10 wt % or more, such as about5 wt % methane and 95 wt % CO₂. It has been surprisingly found that theinclusion of even a small percentage of methane in the production fluid26 can have a demonstrable improvement in system efficiency compared toa produced fluid that is substantially all CO₂, as in a CPG geothermalrecovery system. FIGS. 7A and 7B show pressure-enthalpy phase diagramsfor a 100% CO₂ working fluid cycling through the system (FIG. 7A) and a95% CO₂, 5% methane working fluid (FIG. 7B). Each phase diagram has beenmarked with a hypothetical cycle of the working fluid or productionfluid as it moves through the reservoir 1, is produced to the surfacesystems (e.g., the energy recovery system 32), and re-injected back intothe reservoir 1.

Each of the phase diagram cycles in FIGS. 7A and 7B is marked with five(5) points representing five specific locations within the cycle. Inboth FIG. 7A and FIG. 7B, point “1” represents the injection of theworking fluid 12 at the top of the injection well 14. Point “2”represents the working fluid 12 as it exits the injection well opening16. Point “3” represents the production fluid 26 as it enters theproduction well opening 30. Point “4” represents the point just beforethe production fluid 26 enters the energy recovery system, e.g., justbefore it is sent through an expansion device 36. Point “5” representsthe production fluid 26 after it has exited the energy recovery system32, e.g., from the expansion device 36, but before it has been cooled ina cooling unit 22.

As can be seen from the comparison of FIGS. 7A and 7B, the system thatincludes 5% methane can actually recover more energy within the energyrecovery system 32, as indicated by the greater change in enthalpy alongthe horizontal axis of FIG. 7B between point 4 and point 5, compared tothe change in enthalpy between points 4 and 5 in FIG. 7A. For example,the enthalpy change between points 4 and 5 in FIG. 7A (CO₂ only) isabout 40 kJ/kg of working fluid, while the enthalpy change betweenpoints 4 and 5 in FIG. 7B (CO₂ and methane) is about 50 kJ/kg of workingfluid, or slightly more than a 20% increase in potential energy to beextracted. Although not all of the enthalpy change in the working fluidor production fluid can be recovered by the energy recovery system 32,assuming the efficiency of the energy recovery system 32 recoveringenergy from a CO₂ and methane fluid is substantially the same as theefficiency of the system 32 recovering energy from a pure CO₂ system, itis expected that the difference in enthalpy change will result in ahigher amount of energy being extracted from the production fluid (andthus a higher amount of electricity produced) for a CO₂ and methanesystem compared to a CO₂ only stream as in a CPG system.

In addition, the amount of heat energy that needs to be removed in thecooling unit 22 (represented by the enthalpy change between points 5 and1 in FIGS. 7A and 7B) is less for the CO₂ and methane working fluid orproduction fluid. For example, the enthalpy change between points 5 and1 in FIG. 7A (CO₂ only) is about 215 kJ/kg, while the enthalpy changebetween points 5 and 1 in FIG. 7B (CO₂ and methane) is about 195 kJ/kg,or approximately a 9% decrease in the heat dump that is required withinthe cooling unit 22.

As demonstrated by FIGS. 7A and 7B, the addition of even a small portionof methane (5 wt. %) provides for potentially a 20% increase inelectricity production and a 10% decrease in the cooling load requiredbefore re-injection. This shows that, surprisingly, the extraction ofeven a small portion of methane from the native fluid 2 within areservoir 1 can not only be used to boost temperature or pressure of theproduction fluid, which can increase overall system efficiency (asdescribed above, but also further improves the operating efficiency ofthe system simply by the methane being present.

Waste Heat-Enhanced CPG System

As noted above, in some examples, the reservoir into which the CO₂working fluid is injected, e.g., reservoir 1 in FIGS. 1-4, can comprisea hydrocarbon field that has been partially depleted via conventionaloil or natural gas recovery methods. In these partially-depleted oil andnatural gas fields, the CO₂ can be injected for the purpose of enhancedoil recovery (EOR). Hydrocarbon reservoirs can contain substantialfractions of oil and gas, which can be far more than the smallpercentage of methane that can be dissolved in deep brine aquifers. TheCO₂ working fluid that is injected into such hydrocarbon reservoirs canfree and carry to the surface large quantities of hydrocarbons and otherfluids such that CO₂ constitutes even the minority of the produced flow.In some examples, however, the hydrocarbon field can be substantiallydepleted of hydrocarbons such that they produce very little oil ornatural gas through primary or secondary recovery. In thesesubstantially depleted fields, water or brine and CO₂ can comprise farmore of the flow than do hydrocarbons. In short, the composition of theproduction fluid from an EOR field can be complex and varied. In someexamples, the methane and other hydrocarbons that are produced can bemuch greater than is necessary for enhancing geothermal energy recoveryand for re-injection into the reservoir, so that the additional methaneand other hydrocarbons can be sold in addition to what is kept for usein enhanced CPG operations.

The complex produced fluid from an EOR field, which can generallycomprise a combination of CO₂, hydrocarbons, and water or brine, caneither be separated before or after geothermal heat energy extraction.The heat extraction apparatuses, generally either a direct or a binarypower system, that are employed in an EOR setting can be chosen on asite-specific basis according to produced fluid temperature, pressure,and composition conditions.

In an example, the systems required for EOR operations can be powered byelectricity. The electricity requirements of an EOR system can besubstantially greater than the requirements for a CO₂ plume geothermalsystem or a CO₂ geothermal system including methane combustion tosupplement the geothermal energy recovery. The electricity for EORoperations can be purchased from the grid or through the use of on-sitegas turbines fueled by purchased or locally-produced methane. In thecase of produced methane, power production efficiency and total powerproduced can be increased through the use of the methane-enhancedgeothermal recovery systems described above. The increased efficiency ofthe methane-enhanced systems can be achieved with little or no increasein cost for the site operator because geothermal and gas combustionenergy are combined. Moreover, the overall power costs for an EOR systemthat is supplemented with methane-enhanced geothermal energy recoverycan be decreased because the power produced onsite can be produced fromall available energy types, e.g., geothermal and gas chemical.

One or more components of the geothermal energy recovery system or otherco-located systems, such as an EOR recovery system, can include anoperation or equipment that can generate considerable heat. Often, heatgenerated by these systems, operations, or equipment are allowed todissipate to the atmosphere such that the heat energy is essentiallywasted. This kind of heat is referred to herein as “waste heat.”

An example of waste heat that can occur at or near a geothermal energyrecovery system can include heat generated by a CO₂ compressor. As notedabove, CO₂ working fluid 12 from a CO₂ source 18 can be pressurized in acompressor 20 before it is injected into the injection well 14.Similarly, the CO₂ that is formed during combustion of the separatedmethane 46 to increase the temperature or pressure of the productionfluid 26 and the captured can also be compressed with a compressor 20and injected into the injection well 14. Also, in an enhanced oilrecovery (EOR) system. CO₂ can be produced from the reservoir 1 andseparated from the production fluid 26. The produced CO₂ can becompressed and re-injected back into the reservoir 1. It is understoodin the art that CO₂ compressors, such as those used in EOR systems orfor the compression of CO₂ for injection into a reservoir, such as forCO₂ sequestration, can generate a considerable amount of heat. In anexample, a CO₂ compressor for the injection of CO₂ into the reservoir 1can generate 50 to 1500 kJ of heat energy per kg of CO₂ compressed, suchas 200 to 600 k of heat energy per kg of CO₂ compressed, for example 400to 450 U of heat energy per kg of CO₂ compressed.

Another example of a source of waste heat can occur in an EOR system. Asdescribed above, a production fluid from an EOR field can include CO₂,brine or other native liquids, and hydrocarbons from the oil or gasreservoir. The different components of the production fluid can beseparated, either before the geothermal energy is recovered or after.One method for separating hydrocarbons from the other fluids in theproduction fluid can include burning a portion of the methane or otherhydrocarbons that are produced within a separation vessel, which in turnheats the production fluid. The increased temperature of the productionfluid can improve separation of liquid hydrocarbons from CO₂, naturalgas, and brine. However, the heating to improve separation results in astream of hot liquid hydrocarbons, hot brine, hot CO₂ and natural gas,or any combination thereof, that have conventionally simply been allowedto cool by dissipating the heat to the atmosphere.

Still another example of a source of waste heat can occur with afacility that includes the geothermal energy recovery systems of thepresent disclosure co-located with another type of facility thatproduces excess heat. For example, if the geothermal energy recoveryfacility is co-located with an ethanol or other biofuel productionplant. A co-located ethanol or biofuel plant can be desirable becausesuch plants generally produce CO₂ waste streams during production thatcan be captured and used as the CO₂ source for the geothermal energyrecovery systems of the present disclosure. Other examples of waste heatsources from other facilities include, but are not limited to,fermentation tanks in biofuel facilities, furnaces in industrialfacilities such as cement manufacturing plants, cooling units in fossilfuel power plants, and the heat energy produced at a flare, such as amethane or natural gas flare. Moreover, the CO₂ generated by ethanol andbiofuel plants are typically relatively clean CO₂ streams that can becaptured at a lower cost than CO₂ from fossil fuel power plants.Capturing and injecting the CO₂ from the ethanol or biofuel plant canrequire the use of a CO₂ compressor, which, as noted above, can generateconsiderable waste heat.

The above examples of waste heat are intended to be merely exemplary ofthe sources of waste heat that may be typical or advantageous whenco-located with geothermal energy recovery. The above examples are notintended to be limiting, and a person of ordinary skill in the art canreadily determine whether other waste heat sources can be used tosupplement geothermal energy recovery, as described below.

FIG. 8 shows a non-limiting example of a system 130 where geothermalenergy recovery can be supplemented by waste heat recovery. The system130 of FIG. 8 can include a CO₂ source 132 that is pressurized in acompressor 134 to form a CO₂ working fluid 136 that can be injected intoa reservoir 138 through an injection well 140. The CO₂ working fluid 136off the compressor 134 can be cooled in a cooling unit 135.

The reservoir 138 can include a native fluid 142 that can includemethane 144 in solution within the native fluid 142. In an example, thenative fluid 142 can include oil or other hydrocarbons or brine withinan EOR reservoir 138. The CO₂ working fluid 136 can form a CO₂ plume 146within the reservoir 138 that can comprise CO₂ from the working fluid136, a portion of the methane 144 that is released from solution withinthe native fluid 142, hydrocarbons from the native fluid 142 that arereleased due to the injection of the CO₂ working fluid 136, and othernative fluids such as brine or water (discussed in more detail above).All of these components can form a production fluid 148 that is producedto the surface via a production well 150. In short, the system 130 canbe configured as an enhanced oil recovery (EOR) system. As describedabove, the system 130 can include several subsystems for energy recoveryor conversion that supplements geothermal energy recovery by increasingthe energy that is available to an energy recovery system.

The production fluid 148 can be fed into a separation system 152 thatcan separate the production fluid 148 into its various components. In anexample, the separation system 152 can separate the production fluid 148into a gaseous CO₂ and methane stream 154, a liquid brine or waterstream 156, and a liquid hydrocarbon stream 158. As described above, insome methods separation can be aided in the separation system 152 byheating the production fluid 148 to high temperatures to moreefficiently separate the liquid hydrocarbons 158 from the othercomponents, which can result in all three of the product streams 154,156, and 158 from the separation system 152 being at a high temperature,such as about 30° C. to about 120° C., for example about 50° C. to about80° C.

The heat energy created in the separation system 152 had conventionallybeen allowed to dissipate to the atmosphere as waste heat. The examplesystem 130 of FIG. 8, however, is configured to recover at least aportion of the waste heat from the separation system 152. A secondaryworking fluid 160 can be circulated throughout the system at the surfacein order to recover heat energy from various sources. As shown in theexample of FIG. 8, one or more heat exchangers can be configured torecover heat from the hot separated streams 154, 156, 158, such as afirst heat exchanger 162A on the CO₂/methane stream 154, a second heatexchanger 162B on the brine stream 156, and a third heat exchanger 162Con the liquid hydrocarbon stream 158. The secondary working fluid 160can be split into three separate streams that are fed through the heatexchangers 162 in order to absorb heat from the hot product streams 154,156, 158. The secondary working fluid 160 will also absorb at least aportion of the geothermal energy absorbed by the production fluid 148 inthe reservoir 138. After passing through the heat exchangers 162, thesecondary working fluid 160 can be rejoined for further circulation.

In one example, the separation system 152 may not produce a considerableamount of waste heat, e.g., where liquid hydrocarbon separation can beachieved without further heating. In such a case, the heat exchangers162 can be configured to only absorb the geothermal energy that has beenabsorbed by the production fluid 148 (and which is present in theseparate product streams 154, 156, 158). Alternatively, a single heatexchanger can be positioned upstream or downstream of the separationsystem 152 to absorb the geothermal heat energy.

At least a portion of the cooled CO₂/methane stream 154 can bepressurized by a compressor 164 for re-injection back into the reservoir138 through the injection well 140. The cooled brine or water stream 156can be put into brine storage 166, such as within water or brine tanksor by being injected into a geological formation. At least a portion ofthe cooled liquid hydrocarbon stream 158 can be sold as a hydrocarbonproduct 168.

The secondary working fluid 160 can circulate to other parts of thesystem 130 in order to absorb other heat energy that might otherwise bedissipated to the atmosphere. As described above, the CO₂/methanecompressor 164 can generate considerable heat energy, e.g., about 400 kJto about 450 k per kg of CO₂ and methane being compressed for each stageof compression. In an example, the secondary working fluid 160 can becirculated to the compressor 164 in order to recover a portion of thewaste heat energy. In an example, a heat exchanger (not shown) can beplaced on the CO₂/methane stream 154 immediately downstream of thecompressor 164 to transfer heat energy from the hot CO₂/methane stream154 to the secondary working fluid 160. In another example, thecompressor 164 can be configured so that the secondary working fluid 160flows around or through the compressor 164, e.g., through a coolingjacket on the compressor 164, to absorb heat from the compressor 164.Moreover, heat can be absorbed from the outlet of the compressor (e.g.,immediately downstream of the compressor), or heat can be absorbed afterone or more stages (e.g., from an intercooler) of the compressor.

In an example, the compressor 164 produces more heat energy than theheat energy produced in the separation system 152. For this reason, thecircuit of the secondary working fluid 160 can be configured to firstrecover the heat energy from the separation system 152 (via the heatexchangers 162), and then to recover heat energy from the compressor164.

As discussed above with respect to FIGS. 1-4, a portion of the methaneproduced from the reservoir 138 can be separated from the productionfluid and combusted to supplement energy recovery by increasing thetemperature of a fluid, such as a production fluid or a secondaryworking fluid. The system of FIG. 8 can optionally include this featureof the present disclosure by including a methane separation system 170to separate a portion 172 of the methane from the CO₂/methane stream154. The separated methane 172 can be fed into a combustion heater 174that heats the secondary working fluid 160. In an example, thecombustion heater 174 produces more heat energy than the heat energyproduced in the separation system 152 or the compressor 164. For thisreason, the circuit of the secondary working fluid 160 can be configuredto first recover the heat energy from the separation system 152, thenrecover the heat energy from the compressor 164, and then recover theheat energy from the combustion heater 174.

A portion of the liquid hydrocarbons can be split off from the liquidhydrocarbon stream 158 to be combusted in a heater to further heat thesecondary working fluid 160. In the example shown in FIG. 8, a separatedportion 176 of the liquid hydrocarbon stream 158 can be processed orrefined in a refining or processing system 178 to modify the compositionof the separated liquid hydrocarbons 176 to be more ideal for combustionwithin the heater. The refined or processed liquid hydrocarbons 176 canbe fed into a heater, which can be the same heater 174 in which theseparated methane 172 is combusted (as shown in FIG. 8), or the refinedor processed hydrocarbons 176 can be fed into a separate heater (notshown).

Alternatively, as described above, rather than heating the secondaryworking fluid 160 with a heater 174, the separated methane 172 and theliquid hydrocarbons 176 can be combusted in a conventional gas turbineor gas engine (not shown) to produce electricity from the turbine orengine. The combustion of the hydrocarbon fuel, e.g., the methane 172and the liquid hydrocarbons 176 in the gas turbine or the engine canproduce substantial waste heat in the form of hot combustion gases(e.g., CO₂ and steam) and hot engine or turbine cooling jacket fluid.The waste heat can be added to the working fluid 160, such as via a heatexchanger. This configuration can, in some cases, lead to higher energyconversion efficiency then directly heating the working fluid 160 in aheater 174.

The byproducts of the combustion heater 174 can comprise CO₂, which canbe captured and compressed for re-injection into the reservoir 138,similar to the CO₂ capture system 58 described above with respect toFIG. 1. The captured CO₂ can be fed into the same compressor 164 as theseparated CO₂ and methane 154, or a separate compressor (not shown) canbe used. Waste heat from compressing the captured CO₂ can also berecovered using the secondary working fluid 160.

After the secondary working fluid 160 has recovered heat from each heatsource (e.g., waste heat from the separation system 152 or thecompressor 164, or both, and heat from combustion of separated methane172 or separated liquid hydrocarbons 176 in a combustion heater 174 (ifpresent)), the secondary working fluid 160 can be fed into an energyrecovery system 180 that can convert energy in the secondary workingfluid 160 to another form, such as electricity 182 or direct-use heat.In the example shown in FIG. 8, the energy recovery system 180 includesan expansion device 184 through which the secondary working fluid 160passes to produce shaft power 186. The shaft power 186 can drive agenerator 188 to produce the electricity 182. The secondary workingfluid 160 can then be circulated through a cooling unit 190 beforerestarting the cycle at the heat exchangers 162.

As is further described above, a separate facility, such as a powerplant, a biofuel plant, or an industrial plant can be co-located withthe geothermal energy recovery system of the present disclosure. Wasteheat from such a co-located facility can be recovered using heatexchangers and a working fluid, such as the secondary working fluid 160,that is pumped between the co-located facility and the geothermal energyrecovery system, or the production fluid 148 or one or more of itsconstituent components can be pumped over to the co-located facility sothat the waste heat can be transferred directly to the production fluidor the constituent component or components.

Alternative Configurations

In an example, another combustible fuel, such as natural gas, biomass,or a biofuel (e.g., ethanol or diesel produced from biological sources),can be obtained from a third party outside of the geothermal energyrecovery system. In another example, the other fuel can be produced at aco-located facility, such as a co-located ethanol or other biofuelproduction facility. The other fuel can be used to boost total powerproduction of the geothermal energy recovery system, e.g., by combustingthe outside fuel to increase the temperature, the pressure, or both, ofthe CO₂ based working fluid. For example, if a geothermal energyrecovery facility has been operating for a long period of time such thatthe amount of methane that is being produced from the reservoir is low,then the outside fuel can be used to supplement or replace thenow-defunct methane production. The geothermal heat recovered with theCO₂-based working fluid and the outside fuel source can combine in muchthe same fashion as CO₂-based energy recovery and combusted producedmethane, to increase the overall efficiency of conversion energy toelectricity and to produce more electricity than either system couldprovide alone. In some examples, it may be more economical to purchasenatural gas (mainly CH₄), or other fuels, from a third party rather thanrelying on, or solely relying on, separated CH₄ from the productionfluid. For example, if the cost of natural gas is cheaper than the costof separation. In an example, the fuel used in the combustion heater cancomprise solely natural gas or other outside fuel, such as outsidenatural gas or fuel purchased from a third party, rather than using anyseparated CH₄ produced from the reservoir.

In another example, site development considerations may favor immediateproduction of the methane within the reservoir, rather than long-termsteady production of the methane. For example, rather than ensuregradual methane production over the life of a site, it can be betteroperated by producing the maximum methane that can be extractedbeginning immediately with the onset of CO₂ injection and continuingwhile the CO₂ plume is established. The produced methane can be sold orstored onsite, such as in methane storage tanks or within a geologicformation separate from the reservoir into which the CO₂ working fluidis injected. In the case of sold methane, a portion of the methane canbe purchased back over time to supply the system as needed. In the caseof stored methane, the methane can be removed from storage over time tosupply the system. Immediate production of the methane can beeconomically favorable in circumstances when the well or wells that formethane or brine production can be repurposed for CO₂ circulationwithout the need for separate methane and CO₂ wells. The economicadvantages of repurposing the methane or brine production wells for CO₂circulation can be balanced with the added costs for methane storage(e.g., storage tanks or systems for storing the methane in a geologicalformation).

FIG. 9 shows an example of another system 200 for geothermal energyrecovery from a production fluid 202 produced via a production well 204from a reservoir. The reservoir is not shown in FIG. 9, but a person ofordinary skill in the art will understand that the reservoir can besimilar to the reservoirs shown in FIGS. 1-4 and 8. The system 200 canbe particularly suited for an EOR reservoir, e.g., a reservoir includingnative fluids including methane, oil or other hydrocarbons, and brine.The system 200 can also include an EOR facility 206, e.g., a facilityincluding one or more unit operations for the separation of theproduction fluid 202 into its components, some of which are describedabove with respect to FIG. 8. The geothermal energy present in theproduction fluid 202 can be used to contribute to the process heatenergy used within the EOR facility 206. In other words, the naturalgeothermal energy recovered by the production fluid 202, in addition toproviding for electricity generation as described throughout the presentdisclosure, can also improve the efficiency of the EOR process withinthe EOR facility 206. As demonstrated in FIG. 9, EOR waste process heat208 can be recovered from the EOR facility 206 via any of the techniquesdescribed herein.

The EOR facility 206 can separate a production gas stream 210, which caninclude CO₂, CH₄, and other gaseous hydrocarbons, and water and otherhydrocarbons 211 from the production fluid 202. The system 200 caninclude a compressor or pump 212 downstream of the EOR facility 206 forincreasing the pressure of the production gas stream 210 beforerecovering energy from the production gas stream 210. In particular, thecompressor or pump 212 may be desired if the output pressure of theproduction gas stream 210 from the EOR facility 206 has a relatively lowoutput pressure. The compressor or pump 212 can also compress theproduction gas stream 210 to desired injection conditions so that afterenergy recovery, the production gas stream 210 can be injected back intothe reservoir via an injection well 214.

The compressor or pump 212 can increase the overall efficiency of thesystem. Surprisingly, it has been found that increasing the pressure ofthe production gas stream 210, such as with the compressor or pump 212,can increase the efficiency of the system by more than the amount ofenergy required to compress the production gas stream 210. Waste heat216 from the compressor or pump 212 can be recovered by the system 200,as described in more detail above and below.

After the compressor or pump 212, if present, the production gas stream210 can be fed through an energy recovery apparatus that can be similarto the methods described above, e.g., but first heating the productiongas stream 210 in a heater 218, such as by combusting one or more fuels219 in the heater 218, such as separated CH₄, hydrocarbon fuel from theEOR operation, or other supplied fuel such as supplemental CH₄, or viathe recovery of waste heat in a heat exchanger/heater 218, to increasethe temperature, increase the pressure, or both, of the production gasstream 210. Alternatively, the one or more fuels 219 can be combusted ina conventional gas turbine or gas engine (not shown) to produceelectricity from the turbine or engine, and waste heat (in the form ofhot combustion gases and hot cooling jacket fluid) from the turbine orengine can be added to the production gas stream 210, such as via a heatexchanger, rather than directly heating the production gas fluid 210with a heater 218.

The heated or pressurized production gas stream 210 can be fed through aprimary energy-recovery system 220 to produce electricity 222 directlyfrom the production gas stream 210, such as one or more of a turbine, agenerator, or an energy-recovery loop such as a Rankine power cycle, anorganic Rankine cycle (ORC), or a Kalina cycle. A description of severalexamples of primary energy-recovery systems are described above withrespect to FIGS. 1-4 and 8.

The system 200 of FIG. 9 can also include a secondary energy-recoveryloop 224 to recover additional energy from the hot, low pressureproduction gas stream 210. The secondary energy-recovery loop 224 cancomprise any feasible type of energy-recovery cycle, such as a Rankinepower cycle, an Organic Rankine Cycle (ORC), or a Kalina Cycle. In theexample of FIG. 9, the secondary energy-recovery loop 224 includes anORC-type energy-recovery loop where a secondary working fluid 226 iscirculated through the cycle loop 224. Examples of secondary workingfluids that can be used in the secondary energy-recovery loop 224include, but are not limited to, one or more of CO₂, isobutene, ammonia,or a variety of other fluids. The type of secondary fluid can beselected and optimized depending on the temperature of the productiongas stream 210 directly downstream of the primary energy-recovery system220 as well as the flow rate of the production gas stream 210.

The secondary working fluid 226 can be heated, via a heat exchanger 228,with the hot production gas stream 210 after it has been fed through theprimary generator or turbine system 220. The heated secondary workingfluid 226 can then be fed into a secondary turbine or generator 230 toproduce additional electricity 232. After passing through the secondaryturbine and generator 230, the secondary working fluid 226 can be cooledin a cooling unit 234, and the pressure of the secondary working fluid226 can be increased with a pump or compressor 236 to increase thepressure of the working fluid 226 before starting the cycle over andheating the working fluid 226, such as with the hot, low pressureproduction gas stream 210 in the heat exchanger 228.

Depending on the temperature of the production gas stream 210immediately downstream of the primary energy-recovery system 220, thesecondary energy-recovery loop 224 can comprise a supercritical cycle, atranscritical cycle, a subcritical cycle, or a subcritical withsuperheater cycle.

The secondary energy-recovery loop 224 can provide for energy recoveryfrom relatively lower-temperature sources. Therefore, additionallow-temperature heating sources can be applied to further heat thesecondary working fluid 226 beyond just using the hot production gasstream 210. The additional heating from lower-temperature sources caninclude geothermal energy recovery via a heat exchanger 238 that usesthe production fluid 202 substantially immediately after being producedfrom the production well 204 to heat the secondary working fluid 226.The secondary working fluid 226 can also be further heated in awaste-heat heat exchanger 240 heated by waste heat from other parts ofthe system 200. Waste heat sources that can be particularly useful inthe secondary energy-recovery loop 224 can include waste heat 208 fromthe EOR facility 206 and waste heat 216 from the pump or compressor 212.

It would be difficult to recover heat energy from the relativelylower-temperature energy sources described above using the primaryenergy-recovery system 220 because the CO₂, CH₄, and other gases in theproduction gas stream 210 coming out of the EOR facility 206 or the pumpor compressor 212 can be relatively hot. In contrast, for at leastportions of the secondary energy-recovery loop 224, the secondaryworking fluid 226 can be relatively cool, particular after the coolingunit 234 but before heating the secondary working fluid 226 in the heatexchanger 228 with the hot production gas stream 210.

The secondary working fluid 226 can also be further heated by ahigh-temperature energy source, such as by combusting one or more fuels244, such as separated CH₄, other hydrocarbons from the EOR facility206, or other fuels (such as purchased CH₄), in a secondary combustionheater 242. In an example, the secondary combustion heater 242 operatesat a higher temperature than the hot production gas stream 210, so thatthe secondary heater 242 is placed downstream of the heat exchanger 228as the last source of heat added to the secondary working fluid 226 inthe secondary energy-recovery loop 224. The secondary energy-recoveryloop system 200 of FIG. 9 can be particularly well suited for verylow-temperature geothermal reservoirs, such as those at temperaturesbelow about 75° C.

Additional energy recovery loops, e.g., a tertiary loop, a quaternaryloop, and so on, can be included in the system 200. For example, the hotsecondary working fluid 226 coming out of the secondary turbine orgenerator 230 can be used to heat a tertiary working fluid in a tertiaryenergy-recovery loop, and so on.

FIG. 10 shows an example of another system 250 for geothermal energyrecovery. The system 250 can be similar to the system 200 describedabove with respect to FIG. 9, e.g., the system 250 can provide forenergy recovery from a production fluid 202 produced via a productionwell 204 from a reservoir. The reservoir is not shown in FIG. 10, but aperson of ordinary skill in the art will understand that the reservoircan be similar to the reservoirs shown in FIGS. 1-4 and 8. The system250 can be particularly suited for an EOR reservoir, e.g., a reservoirincluding native fluids including methane, oil or other hydrocarbons,and brine. Like the system 200 of FIG. 9, the system 250 can alsoinclude an EOR facility 206 that can separate the production fluid 202into one or more components, including a production gas stream 210,which can include CO₂, CH₄, and other gaseous hydrocarbons from theproduction fluid 202.

Similar to the system 200 of FIG. 9, the system 250 in FIG. 10 caninclude a compressor or pump 212 downstream of the EOR facility 206 forincreasing the pressure of the production gas stream 210 beforerecovering energy from the production gas stream 210, e.g., if theoutput pressure of the production gas stream 210 from the EOR facility206 has a relatively low output pressure. The compressor or pump 212 canalso compress the production gas stream 210 to desired injectionconditions so that after energy recovery the production gas stream 210can be injected back into the reservoir via an injection well 214.

Like the system 200 of FIG. 9, the system 250 can include sending theproduction gas stream 210 through a primary energy-recovery apparatusafter the compressor or pump 212, if present. For example, theproduction gas stream 210 can be heated in a heater 252, such as bycombusting one or more fuels 254 in the heater 252 to increase thetemperature, increase the pressure, or both, of the production gasstream 210. The heated or pressurized production gas stream 210 can befed through a primary energy-recovery system 256, such as a turbine andgenerator combination, to produce electricity 258.

The system 250 can also include a recuperator heat exchanger 260 torecover heat energy from the hot production gas stream 210 downstream ofthe heater 252 and the primary energy-recovery system 256. Therecuperator heat exchanger 260 uses the relatively high temperature ofthe production gas stream 210 downstream of the primary energy-recoverysystem 256 to increase the temperature of the inlet flow of theproduction gas stream 210 before it enters the heater 252 and theprimary energy-recovery system 256, thus increasing the overallefficiency of the system 250 compared to a system that did not include arecuperator heat exchanger. The recuperator heat exchanger system 250 ofFIG. 10 can be particularly well suited for ver low-temperaturegeothermal reservoirs, such as those at temperatures below about 75° C.

After recovering energy from the production gas stream 210, such as viathe secondary energy-recovery loop 224, as in FIG. 9, or via therecuperator heat exchanger 260, as in FIG. 10, the production gas stream210 can be fed into a separator or separation system 262 that canseparate CO₂ in the production gas stream 210 from CH₄ and other gaseouscomponents in the production gas stream 210 to form a relative pure CO₂stream 264 and a CH₄ and other fuels stream 266. The CO₂ stream can becooled in a cooling unit 268 and compressed in a pump or compressor 270,if desired, for reinjection back into the reservoir through theinjection well 214. The CH₄/fuel stream 266 can be used to supplyheaters of the system 200, 250, such as to form all or part of the fuelstream 219 for the heater 218 (FIG. 9), all or part of the fuel stream254 for the heater 252 (FIG. 10), or all or part of the fuel stream 244for the secondary heater 242 in the secondary energy-recovery loop 224(FIG. 9). A portion of the CH₄/fuel stream 266 can also be used inanother part of the facility (such as in the EOR facility 206, or in aco-located ethanol facility or other co-located facility), or a portionor all of the CH₄/fuel stream 266 can be sold in the open market.

A direct CO₂ turbine may be used after the compressor that is requiredin all CO₂-EOR operations. This configuration may require inclusion of apump/compressor before the turbine (preferably before the methane heaterand waste heat capture unit, as well) if the existing EOR compressor hasan insufficient output pressure. A pump could, alternatively, beincluded after the cooling unit—this configuration may be preferable,since the cold liquid/supercritical stream could relatively easily berecompressed to required injection conditions. Note that the presence ofa pump after the power system is defined in the application in somecases, but the case of a direct turbine after the compressor is notexplicitly specified.

EXAMPLES

The invention will be further described by reference to the followingexamples, which are offered to further illustrate various embodiments ofthe present invention. It should be understood, however, that manyvariations and modifications may be made while remaining within thescope of the present invention. The Examples include numerical modelingof electricity production from various working fluids or productionfluids. The modeling was created using Matlab, sold by The MathWorksInc., Natick, Mass., USA, together with the National Institute ofStandards and Technology (NIST) Reference Fluid Thermodynamic andTransport Properties Database (REFPROP), Version 9.0.

Example 1

FIG. 1A shows the electricity produced (in megawatts (MW)) depending onthe wellhead temperature of the working fluid or the production fluidimmediately after it is produced to the surface. FIG. 11B shows theelectricity produced depending on the bottomhole temperature. Thedifference in temperature between the well bottom temperatures (FIG.11B) and the wellhead temperature (FIG. 1A) are due to Joule-Thompsoncooling, which occurs as the fluid pressure decreases during fluidascent in the production well, such that the fluid bottomholetemperature and pressure are greater than the wellhead temperature andpressure. The calculations employed to create FIGS. 11A and 11B accountfor the Joule-Thompson behavior, which does not occur with water-basedgeothermal working fluids.

The modeling assumed a reservoir depth of 1500 m, a flow rate of theproduction fluid of 200 kg/s, that the production fluid is 99 wt % CO₂and 1 wt % methane, that 2.0 kg/s of the methane is separated andcombusted to boost the temperature, the pressure, or both of theproduction fluid. The expansion device and generator are assumed to havea power system efficiency of 50% of the Carnot efficiency.

FIGS. 11A and 11B both include data lines for the electricity producedby a methane-enhanced CO₂ Plume Geothermal (ME-CPG) system, similar tothe system 10 shown in FIG. 1. Two data lines are shown for ME-CPGsystems, a first line 300 shows the electricity produced if the CO₂ ifthe exhaust stream 56 from the heater 48 is not captured, such as in aCO₂ capture system 58, and a second line 302 shows the electricityproduced if the CO₂ is captured. If a CO₂ capture system 58 is used, itcan use up some of the electricity produced by the energy recoverysystem 32, for example to capture and compress the CO₂, which isdemonstrated by data line 302 in FIGS. 11A and 11B being lower than theline 300. For the models, it is assumed that the CO₂ capture system 58provides 90% capture effectiveness, e.g., 90% of the CO₂ created in theheater 48 is captured by the CO₂ capture system 58, and that thecaptured CO₂ is compressed and injected into the reservoir. For both theCO₂ capture data line 302 and the non-CO₂ capture data line 300, it isassumed that all of the methane in the production fluid is separated andcombusted to increase the temperature of the production fluid, increasethe pressure of the production fluid, or both, 90% of the heat ofmethane combustion is assumed to be transferred to the production fluidand captured by the power cycle.

FIGS. 1A and 11B also show data for geothermal recovery system that doesnot separate and combust released methane. e.g., a CPG only system,represented by line 304, and lines for electricity production from themethane combustion alone, both without CO₂ capture (line 306) and withCO₂ capture (line 308).

As shown in FIGS. 11A and 11B, it has been surprisingly found that therecovery of geothermal energy using a CO₂ and methane production fluidin conjunction with the separation and combustion of a portion of themethane can produce more electricity than the combination of both theCO₂ geothermal energy recovery and combustion of methane alone. In otherwords, the combination of both geothermal energy recovery with a CO₂plume and separation and combustion of methane to boost the temperatureor pressure, or both, of the production fluid is surprisingly moreefficient than what would be expected for the combination of each ofthese energy components by themselves. For example, in FIG. 11A at awellhead temperature of about 100° C., the CPG-only data line 304 showselectricity production of about 17 MW and the methane combustion withCO₂ capture data line 308 shows electricity production of about 18 MW sothat the expected combined electricity production for geothermal energyrecovery using CPG and methane combustion is about 35 MW. However, asshown in FIG. 11A, the methane-enhanced geothermal energy recovery withCO₂ capture data line 302 shows electricity production at a 100° C.wellhead temperature of about 44 MW, which is about 25% higher than the35 MW that would be expected.

Example 2

FIGS. 12A and 12B show similar data comparing a ME-CPG system withoutCO₂ capture (data line 310) and with CO₂ capture (data line 312),CPG-only geothermal energy recovery (data line 314), and methanecombustion only without CO₂ capture (data line 316) and with CO₂ capture(data line 318), but at a reservoir depth of 2500 m, rather than the1500 m in FIGS. 11A and 11B.

Example 3

FIG. 13 shows the electricity produced (in megawatts (MW)) depending onthe wellhead temperature of the production fluid. FIG. 13 includes datafor methane-enhanced geothermal energy production from an EORapplication, where the geothermal energy recovery is furthersupplemented by waste heat capture from a CO₂ compressor.

The modeling for this example assumed a reservoir depth of 1500 m, aflow rate of the production fluid of 100 kg/s. The production fluid isassumed to be 20 wt % CO₂, 1 wt % CH₄, and the remainder liquidhydrocarbons and brine. The flow rate of methane separated from theproduction fluid and combusted is assumed to be 0.5 kg/s. The energyrecovery system for the EOR system is assumed to be a binary system witha secondary working fluid such that energy recovery is less efficientthan the direct turbine system that can be used for Examples 1 and 2.Therefore, the energy recovery system is assumed to have a power systemefficiency of 33% of the Camot efficiency. The waste heat is generatedby a high ratio (10:1) compressor with heat capture only off the finalstage of compression, with no heat capture of any compressorintercoolers. Therefore, additional heat capture from the compressorbeyond that shown in FIG. 13 may be possible.

FIG. 13 includes data for methane-enhanced and waste-heat enhancedgeothermal energy recovery without CO₂ capture of any CO₂ produced bymethane combustion (data line 320) and methane-enhanced and waste-heatenhanced geothermal energy recovery with CO₂ capture (data line 322). Adata line 324 is also included to show the electricity produced justfrom the methane-enhanced geothermal energy recovery. e.g., with nowaste heat capture, and without CO₂ capture. FIG. 13 further includesdata for geothermal recovery system that does not separate and combustreleased methane, e.g., a CPG only system, represented by line 326, datafor electricity production from the methane combustion alone without CO₂capture (line 328), and data for the electricity produced via the wasteheat capture alone (line 330).

As shown in FIG. 13, it has been surprisingly found that the capturingwaste heat to further heat a working fluid in addition to geothermalenergy recovery can produce more electricity than the combination ofboth the geothermal energy recovery and the captured waste heat alone.In other words, the combination of both geothermal energy recovery andwaste heat capture is surprisingly more efficient than what would beexpected for the combination of each of these energy components bythemselves. For example, in FIG. 13 at a wellhead temperature of about100° C., the methane-enhanced geothermal alone (with no waste heatcapture and no CO₂ capture) data line 324 shows electricity productionof about 8.5 MW and the waste heat captured data line 330 showselectricity production of about 1.5 MW so that the expected combinedelectricity production for geothermal energy and waste heat capture isabout 10 MW. However, as shown in FIG. 13, the methane-enhancedgeothermal energy recovery with waste heat capture and no CO₂ captureresults in electricity production at a 100° C. wellhead temperature ofabout 11 MW, which is about 10% higher than the 10 MW that would beexpected.

Various combinations of compressor stages can be used to capture wasteheat for supplementing geothermal energy recovery. FIG. 14 shows theavailable energy (in k per kg of produced fluid) from various sources atvarious bottomhole temperatures. The example energy sources includemethane combustion (line 350), geothermal energy (line 352), waste heatfrom the compressor outlet of a high-ratio, e.g., 10:1, CO₂ compressor(line 354), waste heat from an intercooler for a high-ratio, e.g., 10:1,CO₂ compressor (line 356), waste heat from the compressor outlet of alow-ratio, e.g. 2:1, CO₂ compressor (line 358), and waste heat from anintercooler for a low-ratio, e.g., 2:1, CO₂ compressor (line 360).

Example 4

FIG. 15 shows the electricity produced (in megawatts (MW)) depending onthe volume of methane (in million standard cubic feet per year)combusted. FIG. 15 includes data for methane-enhanced geothermal energyproduction from an EOR application, where the geothermal energy recoveryis further supplemented by waste heat capture from a CO₂ compressor.

FIG. 15 includes data lines for the electricity produced by amethane-enhanced CO₂ Plume Geothermal (E-CPG) system, similar to thesystem 200 shown in FIG. 9, e.g., a CO₂-based production fluid 210 isassumed to be produced from a production well 204, pass through the EORfacility 206, and then into a methane combustion heater 218 and a directCO₂ turbine (e.g., the primary energy-recovery system 220), and is thenis used to heat a secondary energy-recovery loop 224 with ammonia as theworking fluid. The CO₂-based production fluid 210 can then be cooled, ifneeded, compressed, and reinjection into the reservoir.

A first data line 370 in FIG. 15 shows the electricity produced formethane-enhanced CPG (E-CPG) for a CO₂ flow rate of 100 kg/sec andincluding waste heat capture of excess heat from a CO₂ compressorintermediate stage of the EOR facility being added to the enhanced CPGpower system rather than exhausted to the atmosphere, as is commonlydone in FOR operations. A second data line 372 shows the electricityproduced for an E-CPG system for a CO₂ flow rate of 75 kg/sec, also withwaste heat capture. A conservative estimate of 75% of the compressorwaste heat is assumed to be transferred to the enhanced CPG powersystem. The waste heat translates to 109 kJoules/kg CO₂. Note that thiswaste heat quantity is a conservative assumption in some cases, as EORsites may have multiple CO₂ compression steps. Third and fourth datalines 374 and 376, respectively, show the electricity produced at 100kg/sec and 75 kg/sec, respectively, without waste heat capture from theCO₂ compressor.

For each of the data lines 370, 372, 374, 376, the CO₂-based workingfluid is assumed to leave the EOR facility, including CO₂ compressors,at 200 psia (about 13.8 MPa) and 300° F. (about 149° C.), which is amoderate CO₂ injection pressure and a reasonable pre-cooling compressoroutlet temperature. The CO₂ mass flow rate is shown for 100 kg/second(data lines 370 and 374) and 75 kg/second (data lines 372 and 376),which are consistent with a moderately-sized CO₂ EOR facility. Parasiticenergy requirements of the compressors or pumps within the system areaccounted for in the results, but the compressor power required by theEOR facility to raise CO₂ pressure from separation to injectionconditions is not included because the facility requires this energyregardless of whether an enhanced CPG system is included. Either theprimary energy-recovery or the secondary energy-recovery loop can beused to gather the geothermal and, if applicable, waste heat.

Each of the data lines 370, 372, 374, and 376 also includes anassumption of geothermal heat input in the system, the reservoir isassumed to be a relatively low temperature EOR field with moderate oiland water production (6000 barrels/day of each constituent). Geothermalenergy is extracted from the combined CO₂, hydrocarbon, and waterproduction stream, cooling the stream from 57° C. (about 135° F.) toambient conditions. A conservative estimate of 75% of the geothermalenergy is assumed to be transferred to the enhanced CPG power system.

FIG. 15 also include a data line 378 for how much electricity the wasteheat alone could conceivable produce, and a data line 380 for how muchelectricity the geothermal energy alone could potentially produce.Finally, for reference, FIG. 15 also shows the amount of electricitythat could be produced using an off-the-shelf gas turbine (data line382) assumed to have 34% efficiency, and an off-the-shelf gas engine(data line 384) assumed to have 25% efficiency.

As can be seen in FIG. 15, the methane-enhanced CPG system including asecondary energy-recovery loop can provide for dramatically moreelectricity production compared to the geothermal energy alone, thewaste heat alone, or the expected electricity production from methanecombustion alone. As is further shown in FIG. 15, the enhanced CPGsystem with waste heat capture is more efficient than the expectedcombination of the enhanced CPG system alone and the waste heat alone.Finally, as shown in FIG. 15, the total energy produced in the enhancedCPG system with a secondary energy-recovery loop, including waste heat,is more than would be expected for each energy input by itself. FIG. 15therefore shows that the enhanced CPG system with a secondaryenergy-recovery loop and waste heat recovery provides an unexpectedsynergistic benefit beyond what is expected for the combination of eachindividual energy input.

The above Detailed Description is intended to be illustrative, and notrestrictive. For example, the above-described examples (or one or moreelements thereof) can be used in combination with each other. Otherembodiments can be used, such as by one of ordinary skill in the artupon reviewing the above description. Also, various features or elementscan be grouped together to streamline the disclosure. This should not beinterpreted as intending that an unclaimed disclosed feature isessential to any claim. Rather, inventive subject matter can lie in lessthan all features of a particular disclosed embodiment. Thus, thefollowing claims are hereby incorporated into the Detailed Description,with each claim standing on its own as a separate embodiment. The scopeof the invention should be determined with reference to the appendedclaims, along with the full scope of equivalents to which such claimsare entitled.

In the event of inconsistent usages between this document and anydocuments so incorporated by reference, the usage in this documentcontrols.

In this document, the terms “a” or “an” are used, as is common in patentdocuments, to include one or more than one, independent of any otherinstances or usages of “at least one” or “one or more.” In thisdocument, the term “or” is used to refer to a nonexclusive or, such that“A or B” includes “A but not B,” “B but not A,” and “A and B,” unlessotherwise indicated. In this document, the terms “including” and “inwhich” are used as the plain-English equivalents of the respective terms“comprising” and “wherein.” Also, in the following claims, the terms“including” and “comprising” are open-ended, that is, a system, device,article, composition, formulation, or process that includes elements inaddition to those listed after such a term in a claim are still deemedto fall within the scope of that claim. Moreover, in the followingclaims, the terms “first,” “second,” and “third,” etc. are used merelyas labels, and are not intended to impose numerical requirements ontheir objects.

Method examples described herein can be machine or computer-implemented,at least in part. Some examples can include a computer-readable mediumor machine-readable medium encoded with instructions operable toconfigure an electronic device to perform methods or method steps asdescribed in the above examples. An implementation of such methods ormethod steps can include code, such as microcode, assembly languagecode, a higher-level language code, or the like. Such code can includecomputer readable instructions for performing various methods. The codemay form portions of computer program products. Further, in an example,the code can be tangibly stored on one or more volatile, non-transitory,or non-volatile tangible computer-readable media, such as duringexecution or at other times. Examples of these tangiblecomputer-readable media can include, but are not limited to, hard disks,removable magnetic disks, removable optical disks (e.g., compact disksand digital video disks), magnetic cassettes, memory cards or sticks,random access memories (RAMs), read only memories (ROMs), and the like.

The Abstract is provided to comply with 37 C.F.R. § 1.72(b), to allowthe reader to quickly ascertain the nature of the technical disclosure.It is submitted with the understanding that it will not be used tointerpret or limit the scope or meaning of the claims.

1. A system comprising: one or more injection wells for accessing one ormore underground reservoirs, the one or more reservoirs being at one ormore first temperatures and containing at least one native fluid, eachof the one or more injection wells having an injection well reservoiropening in fluid communication with at least one of the one or morereservoirs; one or more production wells, each having a production wellreservoir opening in fluid communication with at least one of the one ormore reservoirs; a working-fluid supply system for providing a non-waterbased working fluid to the one or more injection wells at a secondtemperature lower than the one or more first temperatures, whereinexposure of the working fluid to the first temperatures heats theworking fluid to a third temperature that is higher than the secondtemperature, wherein at least a second portion of the working fluid thatis at the third temperature enters the one or more of the productionwell reservoir openings and is produced from the one or more reservoirsvia the one or more production wells to provide a production fluid; andan energy recovery system that converts energy contained in theproduction fluid to electricity, heat, or a combination thereof, whereinthe energy recovery system includes at least one waste heat recoveryapparatus configured to recover waste heat and use at least a portion ofthe recovered waste heat to heat the production fluid to a fourthtemperature that is higher than the third temperature, wherein the wasteheat is recovered from equipment of or a process stream that flowsthrough the energy recovery system or a co-located system.
 2. The systemof claim 1, wherein the at least one native fluid includes a solutioncomprising methane, wherein exposure of the non-water based workingfluid to the at least one native fluid causes at least a portion of themethane to come out of the solution with the native fluid such that theproduction fluid comprises the portion of the methane and at least aportion of the non-water based working fluid, wherein the energyrecovery system comprises at least one separation apparatus thatseparates at least a portion of the methane from the production fluidand a heater that combusts at least a portion of the separated methane,wherein the combustion generates waste heat, and wherein the at leastone waste heat recovery apparatus is configured to recover at least aportion of the waste heat from combustion of at least the portion of theseparated methane.
 3. The system of claim 2, wherein the at least onenative fluid comprises methane, wherein exposure of the non-water basedworking fluid to the at least one native fluid causes at least a portionof the methane to mix with at least a portion of the non-water basedworking fluid to form the production fluid.
 4. The system of claim 1,wherein the energy recovery system comprises at least one of: one ormore electricity-generating devices; one or more heat exchangers; or acombination thereof to convert energy contained in the production fluidto electricity, heat energy, or a combination thereof.
 5. The system ofclaim 1, wherein the energy recovery system comprises a second heatrecovery apparatus for recovering heat from at least a first portion ofthe production fluid to heat a second portion of the production fluid.6. The system of claim 1, wherein the at least one native fluid furthercomprises at least one hydrocarbon, wherein the production fluidcomprises at least a portion of the at least one hydrocarbon, whereinthe energy recovery system comprises one or more separation units toseparate the at least one hydrocarbon from the production fluid, whereinthe separated hydrocarbon contains waste heat, and wherein the at leastone waste heat recovery apparatus is configured to recover at least aportion of the waste heat from at least one of the one or moreseparation units, the separated at least one hydrocarbon, or theseparated production fluid.
 7. The system of claim 1, wherein thenon-water based working fluid is carbon dioxide.
 8. The system of claim1, wherein the production fluid comprises from 0.01 wt % to 99 wt % ofthe non-water based working fluid.
 9. The system of claim 1, wherein thewaste heat is recovered from equipment in the energy recovery system,the equipment comprising at least one of: a compressor for compressingat least a portion of the production fluid or the working fluid; a pumpfor moving at least a portion of the production fluid or the workingfluid; and an expansion device or generator for electricity generation10. The system of claim 1, wherein the waste heat is recovered from aco-located facility.
 11. The system of claim 1, wherein the co-locatedfacility comprises at least one of: an enhanced oil recovery system; afuel production facility; or a power plant.
 12. The system of claim 1,wherein the at least one native fluid in the one or more undergroundreservoirs comprises a brine aquifer such that at least a portion of theproduction fluid comprises brine recovered from the brine aquifer,wherein the at least one waste heat recovery apparatus includes at leastone heat recovery apparatus configured to recover heat energy from thebrine.
 13. The system of claim 12, wherein the energy recovery systemcomprises one or more separation units to separate the brine from theproduction fluid, wherein the separated brine contains waste heat, andwherein the at least one heat recovery apparatus is configured torecover at least a portion of the waste heat from at least one of theone or more separation units, the separated brine, or the separatedproduction fluid.
 14. A system comprising: one or more injection wellsfor accessing one or more underground reservoirs, the one or morereservoirs being at one or more first temperatures, each of the one ormore injection wells having an injection well reservoir opening in fluidcommunication with at least one of the one or more reservoirs; one ormore production wells each having a production well reservoir opening influid communication with at least one of the one or more reservoirs; aworking-fluid supply system for providing a non-water based workingfluid to the one or more injection wells at a second temperature,wherein exposure of the non-water based working fluid to the one or morefirst temperatures results in heat energy being exchanged between thenon-water based working fluid and the one or more reservoirs to providea production fluid at a third temperature, wherein at least a portion ofthe production fluid at the third temperature enters the production wellreservoir opening and is produced from the reservoir via the one or moreproduction wells to provide a production fluid; and an energy recoverysystem that converts energy contained in the production fluid toelectricity, heat, or a combination thereof, wherein the energy recoverysystem includes equipment that generates waste heat; and wherein theenergy recover system comprises at least one waste heat recoveryapparatus configured to recover at least a portion of the waste heatfrom the equipment and use the recovered portion of the waste heat toheat the production fluid to a fourth temperature that is higher thanthe third temperature to provide a heated production fluid.
 15. Thesystem of claim 14, wherein the equipment that generates waste heatcomprises at least one of: a compressor for compressing at least aportion of the production fluid or the working fluid; a pump for movingat least a portion of the production fluid or the working fluid; anexpansion device or generator for electricity generation; an enhancedoil recovery system; and a co-located facility.
 16. The system of claim15, wherein the co-located facility comprises a fuel production facilityor a power plant.
 17. The system of claim 14, wherein the energyrecovery system further comprises at least one of: one or moreelectricity-generating devices; one or more heat exchangers; or acombination thereof to convert energy contained in the heated productionfluid to electricity, heat energy, or a combination thereof.
 18. Thesystem of claim 14, wherein the one or more reservoirs comprises a brineaquifer and wherein the native fluid comprises brine or apartially-depleted oil or natural gas field wherein the native fluid.19. The system of claim 14, wherein the non-water based working fluid iscarbon dioxide.
 20. The system of claim 14, wherein the production fluidcomprises from 0.01 wt % to 99 wt % of the non-water based workingfluid.